yearend08form10-k.htm

10-K 1 yearend08form10-k.htm FORM 10-K yearend08form10-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2008

OR

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

For the Transition Period from to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number		I.R.S. Employer Identification No.
1-8809		SCANA Corporation (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	57-0784499
1-3375		South Carolina Electric & Gas Company (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	57-0248695

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

Each of the following classes or series of securities is registered on The New York Stock Exchange.

Title of each class	Registrant
Common Stock, without par value	SCANA Corporation
5% Cumulative Preferred Stock par value $50 per share	South Carolina Electric & Gas Company

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

SCANA Corporation x South Carolina Electric & Gas Company x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

SCANA Corporation ¨ South Carolina Electric & Gas Company ¨

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes x No ¨

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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

SCANA Corporation x South Carolina Electric & Gas Company x

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

SCANA Corporation	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨
	Smaller reporting company ¨

South Carolina Electric & Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x
	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).

SCANA Corporation Yes ¨ No x South Carolina Electric & Gas Company Yes ¨ No x

The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $4.3 billion at June 30, 2008 based on the closing price of $37.00 per share. South Carolina Electric & Gas Company is a wholly owned subsidiary of SCANA Corporation and has no voting stock other than its common stock. A description of registrants' common stock follows:

Registrant	Description of Common Stock	Shares Outstanding at February 20, 2009
SCANA Corporation	Without Par Value	121,182,118
South Carolina Electric & Gas Company	$4.50 Par Value	40,296,147(a)

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

Documents incorporated by reference: Specified sections of SCANA Corporation's 2008 Proxy Statement, in connection with its 2009 Annual Meeting of Shareholders, are incorporated by reference in Part III hereof.

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

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TABLE OF CONTENTS

		Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		4
DEFINITIONS		5
PART I
Item 1.	Business	6
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	22
Item 4.	Submission of Matters to a Vote of Security Holders	23
Executive Officers of SCANA Corporation		24
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	26
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
	SCANA Corporation	27
	South Carolina Electric & Gas Company	82
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	122
Item 9A.	Controls and Procedures - SCANA Corporation	122
Item 9A(T).	Controls and Procedures - South Carolina Electric & Gas Company	125
Item 9B.	Other Information	125
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	126
Item 11.	Executive Compensation	129
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	162
Item 13.	Certain Relationships and Related Transactions, and Director Independence	163
Item 14.	Principal Accounting Fees and Services	164
PART IV
Item 15.	Exhibits, Financial Statement Schedules	165
SIGNATURES		167
Exhibit Index		169

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Statements included in this Annual Report on Form 10-K which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include, but are not limited to, statements concerning key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:

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

adjustment;

(2) regulatory actions, particularly changes in rate regulation and environmental regulations;

(3) current and future litigation;

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

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

interruptible markets;

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

(7) the results of short- and long-term financing efforts, including future prospects for obtaining access to

capital markets and other sources of liquidity;

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

(9) the effects of weather, including drought, especially in areas where the generation and transmission

facilities of SCANA and its subsidiaries are located and in areas served by SCANA’s subsidiaries;

(10) payment by counterparties as and when due;

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

(12) the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the

availability of purchased power and natural gas for distribution; the level and volatility of future market

prices for such fuels and purchased power; and the ability to recover the costs for such fuels and

purchased power;

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

(14) inflation;

(15) compliance with regulations; and

(16) the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or

South Carolina Electric & Gas Company (SCE&G) with the United States Securities and Exchange

Commission (SEC), including those risks described in Item 1A. Risk Factors.

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

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DEFINITIONS

The following abbreviations used in the text have the meanings set forth below unless the context requires otherwise:

TERM	MEANING
AFC	Allowance for Funds Used During Construction
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CGTC	Carolina Gas Transmission Corporation
CUT	Customer Usage Tracker
DHEC	South Carolina Department of Health and Environmental Control
DOE	United States Department of Energy
DOJ	United States Department of Justice
Dominion	Dominion Transmission, Inc.
DT	Dekatherm (one million BTUs)
Energy Marketing	The divisions of SEMI, excluding SCANA Energy
EPA	United States Environmental Protection Agency
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GPSC	Georgia Public Service Commission
KW or KWh	Kilowatt or Kilowatt-hour
LLC	Limited Liability Company
LNG	Liquefied Natural Gas
MCF or MMCF	Thousand Cubic Feet or Million Cubic Feet
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW or MWh	Megawatt or Megawatt-hour
NCUC	North Carolina Utilities Commission
NMST	Negotiated Market Sales Tariff
NRC	United States Nuclear Regulatory Commission
NSR	New Source Review
NYMEX	New York Mercantile Exchange
PRP	Potentially Responsible Party
PSNC Energy	Public Service Company of North Carolina, Incorporated
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company
SCANA Energy	A division of SEMI which markets natural gas in Georgia
SCE&G	South Carolina Electric & Gas Company
SCG Pipeline	SCG Pipeline, Inc.
SCI	SCANA Communications, Inc.
SCPC	South Carolina Pipeline Corporation
SCPSC	The Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
SFAS	Statement of Financial Accounting Standards
Southern Natural	Southern Natural Gas Company
Summer Station	V. C. Summer Nuclear Station
Transco	Transcontinental Gas Pipeline Corporation
Williams Station	A.M. Williams Generating Station, owned by GENCO
WNA	Weather Normalization Adjustment

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PART I

ITEM 1. BUSINESS

CORPORATE STRUCTURE

SCANA Corporation (SCANA), a holding company, owns the following direct, wholly-owned subsidiaries.

South Carolina Electric & Gas Company (SCE&G) is engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers and the purchase, sale and transportation of natural gas to retail customers.

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

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

Public Service Company of North Carolina, Incorporated (PSNC Energy) purchases, sells and transports natural gas to retail customers.

Carolina Gas Transmission Corporation (CGTC) transports natural gas in South Carolina and southeastern Georgia.

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

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

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

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

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

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ORGANIZATION

SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G. SCANA and its subsidiaries had full-time, permanent employees as of February 20, 2009 and 2008 of 5,786 and 5,703, respectively. SCE&G is an operating public utility incorporated in 1924 as a South Carolina corporation. SCE&G had full-time, permanent employees as of February 20, 2009 and 2008 of 3,086 and 3,011, respectively.

INVESTOR INFORMATION

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

SEGMENTS OF BUSINESS

For information with respect to major segments of business, see Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 11). All such information is incorporated herein by reference.

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

Regulated Utilities

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to 649,600 customers and the purchase, sale and transportation of natural gas to 307,200 customers (each as of December 31, 2008). SCE&G's business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements. SCE&G's electric service territory extends into 24 counties covering nearly 16,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers more than 23,000 square miles. More than 3.0 million persons live in the counties where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries served by SCE&G include chemicals, health services, textile manufacturing, paper, food products, lumber and wood products, metal fabrication, stone, clay and glass, and retail.

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

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

PSNC Energy purchases, sells and transports natural gas to 467,800 residential, commercial and industrial customers (as of December 31, 2008). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The industrial customers of PSNC Energy include manufacturers and processors of chemicals and allied products, stone, clay and glass products, textiles, and a variety of food and kindred products.

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

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Nonregulated Businesses

SEMI markets natural gas primarily in the southeast and provides energy-related risk management services. SCANA Energy, a division of SEMI, markets natural gas to approximately 460,000 customers (as of December 31, 2008) in Georgia's natural gas market. The GPSC has selected SCANA Energy to serve as the state’s regulated provider until August 31, 2009. Two marketers, including SCANA Energy, have made a bid with the GPSC to be the regulated service provider after SCANA Energy’s current contract expires. SCANA Energy expects a decision in March 2009. Included in the above customer count, SCANA Energy serves over 90,000 customers (as of December 31, 2008) under this regulated provider contract, which includes low-income and high credit risk customers. SCANA Energy's total customer base represents approximately a 30% share of the approximately 1.5 million customers in Georgia's deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

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

The preceding Corporate Structure section describes other businesses owned by SCANA.

COMPETITION

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

CAPITAL REQUIREMENTS

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

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

During the period 2009-2011, SCANA and SCE&G expect to meet capital requirements through internally generated funds, issuance of equity and short-term and long-term borrowings. SCANA and SCE&G expect that they have or can obtain adequate sources of financing to meet their projected cash requirements for the next 12 months and for the foreseeable future.

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

SCANA's ratios of earnings to fixed charges were 3.04, 3.03, 2.94, 2.19 and 2.65 for the years ended December 31, 2008, 2007, 2006, 2005 and 2004, respectively. SCE&G’s ratios of earnings to fixed charges were 3.51, 3.40, 3.32, 2.26 and 3.40 for the same periods. SCE&G’s ratios of earnings to combined fixed charges and preference dividends were 3.29, 3.17, 3.08, 2.10 and 3.15 for the same periods. SCANA’s and SCE&G’s ratios for 2005 were negatively impacted by large amounts of accelerated depreciation that were recorded under an accounting methodology approved by the SCPSC, and because the calculation necessarily excludes the related and fully offsetting synthetic fuel tax benefits recorded in that year.

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ELECTRIC OPERATIONS

Electric Sales

SCE&G's sales of electricity by customer classification as a percent of electric revenues for 2007 and 2008 were as follows:

Customer Classification	2007			2008
Residential		41	%		42	%
Commercial		31	%		31	%
Industrial		17	%		17	%
Sales for resale		7	%		7	%
Other		2	%		2	%
Total Territorial		98	%		99	%
NMST		2	%		1	%
Total		100	%		100	%

SCE&G’s margins earned from the sale of electricity by customer classification as a percent of electric margin for 2007 and 2008 were as follows:

Customer Classification	2007			2008
Residential		47	%		48	%
Commercial		33	%		33	%
Industrial		14	%		14	%
Sales for resale		3	%		2	%
Other		2	%		2	%
Total Territorial		99	%		99	%
NMST		1	%		1	%
Total		100	%		100	%

Sales for resale include sales to seven municipalities. Sales under NMST during 2008 include sales to 13 investor-owned utilities or registered marketers, four electric cooperatives and four federal/state electric agencies. During 2007 sales under the NMST included sales to 20 investor-owned utilities or registered marketers, four electric cooperatives, and four federal/state electric agencies.

During 2008 SCE&G recorded a net increase of 10,300 electric customers (growth rate of 1.6%), increasing its total electric customers to 649,600 at year end.

For the period 2009-2011, SCE&G projects total territorial KWh sales of electricity to increase 2.3% annually (assuming normal weather), total electric customer base to increase 2.4% annually and territorial peak load (summer, in MW) to increase 2.2% annually. While SCE&G's goal is to maintain a reserve margin of between 12% and 18%, weather and other factors affect territorial peak load and can cause actual generating capacity on any given day to fall below the reserve margin goal.

Electric Interconnections

SCE&G purchases all of the electric generation of GENCO's Williams Station under a Unit Power Sales Agreement which has been approved by FERC. Williams Station has a net generating capacity (summer rating) of 615 MW.

SCE&G's transmission system is part of an interconnected grid extending over a large part of the southern and eastern portions of the nation. SCE&G interconnects with Duke Energy Carolinas, Progress Energy Carolinas, and Santee Cooper, and these entities, together with Dominion Virginia Power and APGI (Yadkin Division), are members of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the SERC Reliability Corporation (SERC). SERC is a regional entity of the North American Electric Reliability Corporation (NERC) responsible for promoting, coordinating and ensuring the reliability and adequacy of the bulk power supply systems in the geographic area served by the member systems. SCE&G also interconnects with Georgia Power Company, Oglethorpe Power Corporation and the Southeastern Power Administration's Clarks Hill Project. For a discussion of the impact certain legislative and regulatory initiatives may have on SCE&G's transmission system, see Electric Operations within the Overview section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

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Fuel Costs and Fuel Supply

The average cost of various fuels and the weighted average cost of all fuels (including oil) for the years 2006-2008 follow:

	Cost of Fuel Used
	2006		2007		2008
Per million British thermal units (MMBTU):
Nuclear	$	.43	$	.43	$	.45
Coal		2.54		2.53		3.21
Gas		8.18		8.28		10.92
All Fuels (weighted average)		2.57		2.66		3.50
Per Ton:
Coal	$	63.13	$	62.98	$	79.26
Per thousand cubic feet (MCF):
Gas	$	8.57	$	8.67	$	11.38

The sources and percentages of total MWh generation by each category of fuel for the years 2006-2008 and the estimates for the years 2009-2011 follow:

	% of Total MWh Generated
	Actual							Estimated
	2006			2007		2008		2009		2010		2011
Coal		67	%	63	%	65	%	62	%	63	%	65	%
Nuclear		19	%	21	%	18	%	19	%	21	%	19	%
Hydro		4	%	4	%	4	%	5	%	6	%	5	%
Natural Gas & Oil		10	%	12	%	13	%	14	%	10	%	11	%
Total		100	%	100	%	100	%	100	%	100	%	100	%

Six of the seven fossil fuel-fired plants use coal. Unit trains and in some cases trucks and barges deliver coal to these plants.

Coal is obtained through long-term supply contracts and spot market purchases. Long-term contracts exist with eleven suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 5.6 million tons annually, which is 79% of total expected coal purchases for 2009. Sulfur restrictions on the contract coal range from 1.0% to 2.0%. These contracts expire at various times through 2011. Spot market purchases are expected to continue when needed or when prices are believed to be favorable.

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

SCE&G has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station through 2016. The following table summarizes contract commitments for the stages of nuclear fuel assemblies:

Commitment	Contractor	Remaining Regions(a)	Expiration Date
Uranium	United States Enrichment Corporation	21-25	2016
Enrichment	United States Enrichment Corporation	21-24	2014
Fabrication	Westinghouse Electric Corporation	21-22	2011

(a) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region 20 was loaded in 2008.

SCE&G can store spent nuclear fuel on-site until at least 2018 and expects to expand its storage capacity to accommodate the spent fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available. In addition, Summer Station has sufficient on-site storage capacity to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract with the DOE regarding disposal of spent fuel, see Hazardous and Solid Wastes within the Environmental Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

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GAS OPERATIONS

Gas Sales-Regulated

Sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 2007 and 2008 were as follows:

	SCANA						SCE&G
Customer Classification	2007			2008			2007			2008
Residential		51.1	%		50.0	%		40.5	%		36.8	%
Commercial		29.6	%		29.8	%		30.4	%		30.5	%
Industrial		16.1	%		17.0	%		28.4	%		31.6	%
Transportation Gas		3.2	%		3.2	%		0.7	%		1.1	%
Total		100	%		100	%		100	%		100	%

For the three-year period 2009-2011, SCANA projects total consolidated sales of regulated natural gas in DTs to increase 1.3% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 2.1%, commercial of 1.1% and industrial of 0.9%.

For the three-year period 2009-2011, SCE&G projects total consolidated sales of regulated natural gas in DTs to increase 0.6% annually (assuming normal weather). Annual projected increases (decreases) over such period in DT sales include residential of (0.4)%, commercial of 0.1% and industrial of 1.7%.

For the three-year period 2009-2011, SCANA's and SCE&G’s total consolidated regulated natural gas customer base is projected to increase annually 2.5% and 1.0%, respectively. During 2008 SCANA recorded a net increase of 15,000 regulated gas customers (growth rate of 2.0%), increasing its regulated gas customers to 774,000. Of this increase, SCE&G recorded a net increase of 4,600 gas customers (growth rate of 1.5%), increasing its total gas customers to 307,200 (as of December 31, 2008).

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

Gas Cost, Supply and Curtailment Plans

South Carolina

SCE&G purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. The gas is brought to South Carolina through transportation agreements with Southern Natural (expiring in 2010), Transco (expiring in 2011 and 2017) and CGTC (expiring in 2011 and 2012). The daily volume of gas that SCE&G is entitled to transport under these contracts on a firm basis is 161,143 DT from Southern Natural, 64,652 DT from Transco and 314,529 DT from CGTC. Natural gas volumes may be brought to SCE&G's system as capacity is available for interruptible transportation. In addition, SCE&G, under contract with SEMI, is entitled to receive a daily contract demand of 120,000 DTs for use in either electric generation or for resale to SCE&G’s customers.

The daily volume of gas that SEMI is entitled to transport under its service agreement with CGTC (expiring in 2023) on a firm basis is 198,083 DT.

SCE&G purchased natural gas at an average cost of $10.50 per MCF during 2008 and $9.69 per MCF during 2007.

SCE&G was allocated 5,406 MMCF of natural gas storage capacity on Southern Natural and Transco. Approximately 5,118 MMCF of gas were in storage on December 31, 2008. To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCE&G supplements its supplies of natural gas with two LNG liquefaction and storage facilities. The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately 1,756 MMCF (liquefied equivalent) of gas were in storage at December 31, 2008.

North Carolina

PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at current prices and on a long-term basis for reliability assurance at index prices plus a reservation charge. Transco and Dominion deliver the gas to North Carolina through transportation agreements with expiration dates ranging through 2016. On a peak day, PSNC Energy may transport daily volumes of gas under these contracts on a firm basis of 259,894 DT from Transco and 7,331 DT from Dominion.

PSNC Energy purchased natural gas at an average cost of $10.18 per DT during 2008 compared to $8.55 per DT during 2007.

To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and LNG peaking services. Underground natural gas storage service agreements with Dominion, Columbia Gas Transmission, Transco and Spectra Energy provide for storage capacity of approximately 13,000 MMCF. Approximately 10,500 MMCF of gas were in storage under these agreements at December 31, 2008. In addition, PSNC Energy's LNG facility can store the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day. Approximately 800 MMCF (liquefied equivalent) of gas were in storage at December 31, 2008. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,100 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2008.

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

Gas Marketing-Nonregulated

SEMI markets natural gas and provides energy-related risk management services primarily in the Southeast. In addition, SCANA Energy, a division of SEMI, markets natural gas to approximately 460,000 customers (as of December 31, 2008) in Georgia's natural gas market. SCANA Energy's total customer base represents approximately a 30% share of the approximately 1.5 million customers in Georgia's deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

Risk Management

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

REGULATION

SCANA, together with its subsidiaries, is subject to the jurisdiction of the SEC and FERC as to the issuance of certain securities, acquisitions and other matters. State public service commissions or FERC regulate certain subsidiaries of SCANA as to the following matters.

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 is subject to the jurisdiction of FERC as to issuance of short-term borrowings and other matters.

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

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

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

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

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

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of such short-term indebtedness. The authority to make such issuances will expire on February 6, 2010.

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

Project	License Expiration	Project	License Expiration
Saluda (Lake Murray)	2010	Stevens Creek	2025
Fairfield Pumped Storage	2020	Neal Shoals	2036
Parr Shoals	2020

SCE&G applied to FERC for relicensing of the Saluda project on August 27, 2008. This application is currently being reviewed by FERC.

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

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

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

RATE MATTERS

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

SCE&G's gas rate schedules for its residential, small commercial and small industrial customers include a WNA. SCE&G's WNA was approved by the SCPSC and is in effect for bills rendered during the period November 1 through April 30 of each year. The WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues, but reduces fluctuations in revenues and earnings caused by abnormal weather.

Prior to November 1, 2008, PSNC Energy had in effect an NCUC-approved WNA for its natural gas rate schedules, with similar, though not identical, provisions to those of SCE&G’s WNA mechanism. Effective November 1, 2008, PSNC Energy was authorized by the NCUC to implement a CUT, a rate decoupling mechanism that breaks the link between revenues and the amount of natural gas sold. The CUT allows PSNC Energy to periodically adjust its base rates for residential and commercial customers based on average per customer consumption whether impacted by weather or other factors.

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Fuel Cost Recovery Procedures

The SCPSC’s fuel cost recovery procedure determines the fuel component in SCE&G's retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any overcollection or undercollection from the preceding 12-month period. The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, mercury and particulates. SCE&G may request a formal proceeding at any time should circumstances dictate such a review. On October 30, 2008, the SCPSC approved a settlement agreement between SCE&G and the South Carolina Office of Regulatory Staff (ORS), whereby SCE&G increased the fuel cost portion of its electric rates. SCE&G sought the increase due to significant increases in fuel costs through the first half of 2008. The increase was effective with the first billing cycle of November 2008.

SCE&G's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas cost incurred, including costs related to hedging natural gas purchasing activities. SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a twelve-month rolling average.

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

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

ENVIRONMENTAL MATTERS

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

OTHER MATTERS

For a discussion of SCE&G's insurance coverage for Summer Station, see Note 10A to the consolidated financial statements for SCANA and SCE&G.

ITEM 1A. RISK FACTORS

The risk factors that follow relate in each case to SCANA Corporation and its subsidiaries (the Company), and where indicated the risk factors also relate to South Carolina Electric & Gas Company and its consolidated affiliates (SCE&G).

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

Our energy businesses are sensitive to changes in coal, gas, oil and other commodity prices and availability. Any such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. SCE&G is able to recover the cost of fuel (including transportation) used in electric generation through retail customers' bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources. In the case of regulated natural gas operations, costs for purchased gas and pipeline capacity are recovered through retail customers' bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in gas costs may also result in lower usage by customers unable to switch to alternate fuels. Increases in fuel costs may also result in lower usage of electricity by customers.

Additionally, the Company and SCE&G anticipate significant capital expenditures for environmental compliance and baseload generation in order to meet future usage demands. The cost of additional baseload generation may be affected by the choice of technology or fuel related to such generation, each of which may be driven by environmental and other non-economic factors. The completion of these projects within established budgets and timeframes is contingent upon many variables including the obtaining of permits and licenses in a timely manner, our timely securing of labor and materials at estimated costs and our ability to finance such projects. Recently, certain construction commodities such as steel, copper (used in our transmission and distribution lines) and concrete have experienced significant price volatility due to changing worldwide demand. Also, to operate our air pollution control equipment, we use significant quantities of ammonia and lime. With mandated compliance deadlines for air pollution controls, demand for these reagents may increase and result in higher purchase costs. Our ability to maintain our operations or to complete construction projects and new baseload generation at reasonable cost, if at all, could be adversely affected by increases in worldwide demand for key parts or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, increased environmental pressures, a failure in the supply chain (whether resulting from the foregoing or other factors), disruptions in the transportation of fuels, or delays in licensing, siting, design, financing or construction. To the extent that delays occur or cost overages are not recoverable, our results of operations, cash flows and financial condition may be diminished.

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

The Company and SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. In the future, we could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and interest rate contracts or if a counterparty fails to perform under a contract.

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

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

The Company and SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, Internal Revenue Service, EPA, and a number of others. In addition, the Company and SCE&G are subject to regulation by agencies of the state governments of South Carolina, North Carolina, and Georgia, including regulatory commissions, state environmental commissions, state employment commissions, and a number of others. Accordingly, the Company and SCE&G must comply with extensive federal, state and local laws and regulations. Such regulation widely affects the operation of our business. The effects encompass, among many other aspects of our business, the licensing and siting of facilities, safety, reliability of our transmission system, physical and cyber security of key assets, information privacy, the issuance of securities and borrowing of money, financial reporting, interaction among affiliates, the payment of dividends, and employment practices. Changes to these regulations are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or SCE&G’s business.

The Company and SCE&G are subject to extensive rate regulation which could adversely affect operations. In particular, SCE&G's electric operations in South Carolina and the Company's gas distribution operations in South Carolina (comprised of SCE&G) and North Carolina are regulated by state utilities commissions. The Company’s interstate gas pipeline is subject to federal oversight. Our gas marketing operations in Georgia are also subject to state regulatory oversight. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve. Although we believe we have constructive relationships with our regulators, our ability to obtain rate increases that will allow us to maintain reasonable rates of return is dependent upon regulatory discretion, and there can be no assurance that we will be able to implement rate increases when sought.

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

The Company and SCE&G are presently subject to extensive federal, state and local environmental laws and regulations including air emissions (such as reducing emissions of nitrogen oxide, sulfur dioxide and particulate matter). There is growing consensus that some form of regulation will be forthcoming at the federal, and possibly state, levels to impose limitations on greenhouse gas (GHG) and mercury emissions from fossil fuel-fired electric generating units and to further regulate coal ash. Compliance with these laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at our facilities. These expenditures have been significant in the past and are expected to increase in the future. Changes in compliance requirements or a more burdensome interpretation by governmental authorities of existing requirements may impose additional costs on us (such as additional taxes or emission allowances) or require us to incur additional capital expenditures or curtail some of our activities. In addition, such costs of compliance with proposed environmental regulations could harm our industry, our business and our results of operations and financial position, especially if emission or discharge limits are reduced, more extensive permitting requirements are imposed or additional regulatory requirements are imposed.

Furthermore, the Company and SCE&G are subject to the possibility that electric generation portfolio standards may be enacted at the federal or state level. Such standards could direct us to build or otherwise acquire generating capacity derived from alternative energy sources (generally, renewable energy such as biomass, solar, wind and tidal, and excluding fossil fuels, nuclear or hydro facilities). Such alternative energy may not be readily available in our service territories, and could be extremely costly to build or acquire, if at all, and to operate. Resulting increases in the price of electricity to recover the cost of these types of generation, if approved by regulatory commissions, could result in lower usage of electricity by our customers. Although we cannot predict whether such standards will be adopted or their specifics if adopted, compliance with such potential portfolio standards could significantly impact our industry, our capital expenditures, and our results of operations and financial position.

The Company and SCE&G are vulnerable to interest rate increases which would increase our borrowing costs, and may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.

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

In mid-September 2008, a very severe dislocation of the commercial paper, long-term debt and equity markets occurred as concerns over bank solvency adversely affected the credit markets. Access to the commercial paper markets was very limited. Commercial paper outstanding was significantly reduced, and the interest rates on commercial paper outstanding significantly increased. Access to the debt capital markets was also very limited. While the credit and capital markets have since improved, the effects of the dislocation are continuing. The Company and SCE&G cannot predict when or if the current dislocation will end, or if similar dislocations will occur in the future.

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

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

The Company's and SCE&G's business is capital intensive and the costs of capital projects may be significant.

The Company's and SCE&G's business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. For example, SCE&G and Santee Cooper have agreed to jointly own, design, construct and operate two new 1,117-megawatt nuclear units at SCE&G's V.C. Summer Nuclear Station (the "New Units"), pursuant to which they plan to expend substantial resources to the evaluation, development and permitting of the project, site preparation and long lead-time procurement; substantial additional resources will be required for the construction and continued operation of the plant upon receipt of requisite approvals. A large capital project of this type is subject to a number of uncertainties that may impact the cost, timeliness and completion of the project and which may also adversely affect the achievement of the project’s intended benefits. The Company's and SCE&G’s results of operations, cash flows and financial position could be adversely affected if they were unable to effectively manage their capital projects.

SCANA may not be able to maintain its leverage ratio at a level considered appropriate by debt rating agencies. This could result in downgrades of SCANA's and SCE&G’s debt ratings, thereby increasing their borrowing costs and adversely affecting their results of operations, cash flows and financial condition.

SCANA's leverage ratio of debt to capital was approximately 59% at December 31, 2008. SCANA has publicly announced its desire to achieve a leverage ratio at 54% to 57%, but SCANA's ability to do so depends on a number of factors. If SCANA is not able to maintain its leverage ratio, SCANA's and SCE&G’s debt ratings may be affected, they may be required to pay higher interest rates on their long- and short-term indebtedness, and their access to the capital markets may be limited.

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

Standard & Poor's Ratings Services (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) rate SCANA's long-term senior unsecured debt at BBB+, Baa1 and A-, respectively. S&P, Moody's and Fitch rate SCE&G's long-term senior secured debt at A-, A2 and A+, respectively. S&P, Moody’s and Fitch rate PSNC Energy's long-term senior unsecured debt at A-, A3 and A, respectively. Moody’s carries a stable outlook on each of its ratings. S&P and Fitch carry a negative outlook on each of their ratings. If S&P, Moody's or Fitch were to downgrade any of these long-term ratings, particularly to below investment grade, borrowing costs would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease. S&P, Moody's and Fitch rate the short-term debt of SCE&G and PSNC Energy at A-2, P-2 and F-2, respectively. If these short-term ratings were to decline, it could significantly limit access to sources of liquidity.

Operating results may be adversely affected by abnormal weather.

The Company and SCE&G have historically sold less power, delivered less gas and received lower prices for natural gas in deregulated markets, and consequently earned less income, when weather conditions have been milder than normal. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and SCE&G. In addition, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

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

The utility industry has been undergoing dramatic structural change for several years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales has been introduced on a national level. Some states have also mandated or encouraged competition at the retail level. Increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, SCANA's and SCE&G's generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets would be required.

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

Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Some economic sectors important to our customer base may be particularly affected. Adverse events, economic or otherwise, may also affect the operations of key customers. Such events may result in changes in usage patterns and in the failure of customers to make timely payments to us. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales.

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

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

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

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

In particular, as the operator of power generation facilities, SCE&G could incur problems such as the breakdown or failure of power generation or emission control equipment, transmission lines, other equipment or processes which would result in performance below assumed levels of output or efficiency. In addition, any such breakdown or failure may result in SCE&G purchasing replacement power at market rates, if such replacement power is available at all. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. These purchases are subject to state regulatory prudency reviews for recovery through rates.

Covenants in certain financial instruments may limit SCANA's ability to pay dividends, thereby adversely impacting the valuation of our common stock and our access to capital.

Our assets consist primarily of investments in subsidiaries. Dividends on our common stock depend on the earnings, financial condition and capital requirements of our subsidiaries, principally SCE&G, PSNC Energy and SEMI. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.

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

In 2008, the V.C. Summer Nuclear Station, operated by SCE&G, provided approximately 4.7 million MWh, or 19% of our generation capacity, both of which figures are expected to increase if the New Units are completed. As such, SCE&G is subject to various risks of nuclear generation, which include the following:

·	The potential harmful effects on the environment and human health resulting from a release of radioactive

materials in connection with the operation of nuclear facilities and the storage, handling and disposal of

radioactive materials;

·	Limitations on the amounts and types of insurance commercially available to cover losses that might arise

in connection with our nuclear operations or those of others in the United States;

·	Uncertainties with respect to procurement of enriched uranium fuel and the storage of spent uranium fuel;

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

·	Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at

the end of their operating lives.

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

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

Implementation of our strategic plan and growth strategy requires that we attract, retain and develop executive officers and other professional and technical employees with the skills and experience necessary to successfully manage our operations and grow our business. Competition for these employees is high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed.

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable

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ITEM 2. PROPERTIES

SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G.

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

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

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

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ELECTRIC PROPERTIES

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

Facility	Present Fuel Capability	Location	Year In-Service	Net Generating Capacity (Summer Rating) (MW)
Steam Turbines:
Summer(1)	Nuclear	Parr, SC	1984	644
McMeekin	Coal/Gas	Irmo, SC	1958	250
Canadys	Coal/Gas	Canadys, SC	1962	400
Wateree	Coal	Eastover, SC	1970	700
Williams(2)	Coal	Goose Creek, SC	1973	610
Cope	Coal	Cope, SC	1996	420
Cogen South(3)	Biomass/Coal	Charleston, SC	1999	90

Combined Cycle:
Urquhart(4)	Coal/Gas/Oil	Beech Island, SC	1953/2002	555
Jasper	Gas/Oil	Hardeeville, SC	2004	857

Hydro(5):
Saluda		Irmo, SC	1930	200
Fairfield Pumped Storage		Parr, SC	1978	576

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

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

(3) SCE&G receives shaft horsepower from Cogen South, LLC, a biomass/coal cogeneration facility, to operate

SCE&G's generator.

(4) Two combined-cycle turbines burn natural gas or fuel oil to produce 318 MW of electric generation and use exhaust

heat to power two 75 MW turbines at the Urquhart Generating Station. Unit 3 is a coal-fired steam unit.

(5) SCE&G also owns three other hydro units in South Carolina that were placed in service in 1905 and 1914 and have

an aggregate net generating capacity of 21 MW.

SCE&G owns fourteen combustion turbine peaking units fueled by gas and/or oil located at various sites in SCE&G's service territory. These turbines were placed in service at various times from 1961 to 1999 and have aggregate net generating capacity of 314 MW.

SCE&G owns 436 substations having an aggregate transformer capacity of 27.4 million KVA (kilovolt-ampere). The transmission system consists of 3,247 miles of lines, and the distribution system consists of 18,117 pole miles of overhead lines and 6,392 trench miles of underground lines.

NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES

SCE&G’s natural gas system consists of 15,714 miles of distribution mains and related service facilities. SCE&G also owns two LNG plants, one located near Charleston, South Carolina and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF of natural gas. The Salley facility can store the liquefied equivalent of 900 MMCF of natural gas and has no liquefying capabilities. The LNG facilities have the capacity to regasify approximately 60 MMCF at Charleston and 90 MMCF at Salley.

CGTC’s natural gas system consists of 1,468 miles of transmission pipeline of up to 24 inches in diameter. CGTC’s system transports gas to its customers from the transmission systems of Southern Natural and Transco and from Port Wentworth and Elba Island, Georgia.

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PSNC Energy’s natural gas system consists of 615 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy's distribution system consists of 9,828 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly-owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC Energy owns, through a wholly owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.

ITEM 3. LEGAL PROCEEDINGS

Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2008, are described below. These issues affect SCANA and, to the extent indicated, also affect SCE&G.

Environmental Matters

SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List in April 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2009. The site has not been remediated nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

SCE&G is responsible for four MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $9.5 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates. At December 31, 2008, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $4.5 million, the estimated remaining liability at December 31, 2008. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

Litigation

In February 2008, the consumer affairs staff (the staff) of the GPSC recommended that the GPSC open an investigation into whether SCANA Energy had overcharged certain of its customers. The staff asserted that SCANA Energy confused certain customers, charged certain customers in excess of the published prices, and failed to give proper notice of an alleged change in methodology for computing variable rates. While SCANA Energy believed and continues to believe the staff’s assertions were without merit, in June 2008 SCANA Energy entered into a settlement agreement with the GPSC, agreeing to pay $1.25 million in the form of credits on certain customers’ bills and as a contribution to low-income assistance programs. As of December 31, 2008, credits and contributions totaling $1.15 million had been provided to those customers and programs.

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On February 26, 2008, a purported class action was filed in U.S. District Court for the Northern District of Georgia, originally styled Weiskircher, et al. v. SCANA Energy Marketing, Inc., containing similar allegations to those alleged by the staff and seeking damages on behalf of a class of Georgia customers. On June 13, 2008 the court dismissed the suit with prejudice. The plaintiffs subsequently filed a motion for reconsideration, which was denied. On August 28, 2008, the plaintiffs filed a notice of appeal. SCANA Energy believes the allegations are without merit and will vigorously defend itself. Although the Company cannot predict the final outcome, it believes that a resolution of this matter will not have a material adverse impact on its results of operations, cash flows or financial condition.

In September 2006, a patent infringement action styled as Jaime G. Garcia vs. SCANA Corporation was filed in U.S. District Court for the District of South Carolina. The plaintiff alleged that the repowering of SCE&G’s Urquhart Station from 2000 to 2002 violated his patent dealing with condenser performance in steam power plants and sought damages including interest, attorney’s fees and costs. The complaint was subsequently amended substituting SCE&G for SCANA as the defendant. In November 2008 the court ruled in favor of SCE&G’s motion for summary judgment on the grounds of non-infringement and denied the plaintiff’s motion on the same basis. The plaintiff did not appeal the court’s ruling, thus ending the case.

In May 2004, a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims. SCANA and SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted SCANA’s and SCE&G’s motion to dismiss and issued an order dismissing the case in June 2005. The plaintiff appealed to the South Carolina Supreme Court. The Supreme Court reversed the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration. In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to owners of easements situated in Charleston County, South Carolina. The South Carolina Court of Appeals dismissed the plaintiff’s appeal of this ruling, determining that the Circuit Court ruling was not immediately appealable. On February 27, 2008 the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County. In July 2008, the plaintiff’s motion to add SCI to the lawsuit as an additional defendant was granted. The parties filed motions for partial summary judgment, and the plaintiff moved to expand the class. In December 2008 these motions were heard and denied by the court. Trial is not anticipated before the fall of 2009. SCANA, SCI and SCE&G will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

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EXECUTIVE OFFICERS OF SCANA CORPORATION

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

Name	Age	Positions Held During Past Five Years	Dates

William B. Timmerman	62	Chairman of the Board, President and Chief Executive Officer	*-present
Jimmy E. Addison	48	Senior Vice President and Chief Financial Officer Vice President-Finance	2006-present *-2006
Joseph C. Bouknight	56	Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA	2004-present *-2004
George J. Bullwinkel	60	President and Chief Operating Officer-SEMI President and Chief Operating Officer-SCI and ServiceCare President and Chief Operating Officer-SCPC and SCG Pipeline	2004-present -present -2004
Sarena D. Burch	51	Senior Vice President-Fuel Procurement and Asset Management-SCE&G and PSNC Energy Senior Vice President-Fuel Procurement and Asset Management-SCPC	-present -2006
Stephen A. Byrne	49	Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G Senior Vice President-Nuclear Operations	2004-present *-2004
Paul V. Fant	55	President and Chief Operating Officer-CGTC (formerly SCPC and SCG Pipeline) Senior Vice President - SCANA Senior Vice President - Transmission Services – SCE&G Executive Vice President-SCPC and SCG Pipeline	2004-present 2008-present 2004-2007 *-2004
Kevin B. Marsh	53	President and Chief Operating Officer - SCE&G Senior Vice President and Chief Financial Officer	2006-present *-2006
Charles B. McFadden	64	Senior Vice President-Governmental Affairs and Economic Development- SCANA Services	*-present
Francis P. Mood, Jr.	71	Senior Vice President, General Counsel and Assistant Secretary Attorney, Haynsworth Sinkler Boyd, P.A.-Columbia, SC	2005-present *-2005

* Indicates position held at least since March 1, 2004.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,

AND ISSUER PURCHASES OF EQUITY SECURITIES

COMMON STOCK INFORMATION

SCANA Corporation:

Price Range (New York Stock Exchange Composite Listing):

	2008					2007
	4th Qtr.		3rd Qtr.	2nd Qtr.	1st Qtr.	4th Qtr.	3rd Qtr.	2nd Qtr.	1st Qtr.

High	$40.24	$44.06		$41.32	$42.70	$43.73	$39.75	$45.49	$43.51
Low	$27.75	$35.02		$36.60	$35.83	$38.69	$32.93	$37.91	$39.92

SCANA common stock trades on The New York Stock Exchange, using the ticker symbol SCG. Newspaper stock listings use the name SCANA. At February 20, 2009 there were 121,182,118 shares of SCANA Common Stock outstanding which were held by approximately 31,964 stockholders of record. For a summary of equity securities issuable under SCANA's compensation plans at December 31, 2008, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

SCANA declared quarterly dividends on its common stock of $.46 per share in 2008 and $.44 per share in 2007. On February 19, 2009, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.47 per share, an increase of 2.0%. The new dividend is payable April 1, 2009 to stockholders of record on March 10, 2009. For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENTS’ DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources – Financing Limits and Related Matters and Note 6 to the consolidated financial statements for SCANA.

SCE&G:

All of SCE&G's common stock is owned by SCANA and is not traded. During 2008 and 2007 SCE&G paid $153.8 million and $131.9 million, respectively, in cash dividends to SCANA. For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENTS’ DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources – Financing Limits and Related Matters and Note 6 to the consolidated financial statements for SCE&G.

SECURITIES RATINGS (As of February 20, 2009)

	SCANA	SCE&G
Rating Agency	Senior Unsecured	Senior Secured	Senior Unsecured	Preferred Stock	Commercial Paper	Outlook
Moody's	Baa1	A2	A3	Baa2	P-2	Stable
S&P	BBB+	A-	A-	BBB	A-2	Negative
Fitch	A-	A+	A	A-	F-2	Negative

For additional information regarding these securities, see Notes 4, 5 and 7 to the consolidated financial statements for SCANA and SCE&G.

Securities ratings used by Moody's, S&P and Fitch are as follows:

Long-term (investment grade)			Short-term
Moody's (1)	S&P (2)	Fitch (2)	Moody's	S&P	Fitch
Aaa	AAA	AAA	Prime-1 (P-1)	A-1	F-1
Aa	AA	AA	Prime-2 (P-2)	A-2	F-2
A	A	A	Prime-3 (P-3)	A-3	F-3
Baa	BBB	BBB	Not Prime	B	B
				C	C
				D	D

(1) Additional Modifiers: 1, 2, 3 (Aa to Baa) (2) Additional Modifiers: +, - (AA to BBB)

A security rating should be evaluated independently of other ratings and is not a recommendation to buy, sell or hold securities. The assigning rating organization may revise or withdraw its security ratings at any time.

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ITEM 6. SELECTED FINANCIAL DATA

	SCANA																SCE&G
As of or for the Year Ended December 31,	2008			2007				2006			2005			2004			2008			2007			2006			2005			2004
	(Millions of dollars, except statistics and per share amounts)
Statement of Income Data
Operating Revenues	$	5,319			$	4,621		$	4,563		$	4,777		$	3,885		$	2,816		$	2,481		$	2,391		$	2,421		$	2,089
Operating Income		710				633			603			436			596			559			498			468			312			475
Other Income (Expense)		(183	)			(160	)		(164	)		(162	)		(219	)		(122	)		(117	)		(121	)		(121	)		(111	)
Income Before Cumulative Effect of Accounting Change (1)		346				320			304			320			257			273			245			230			258			232
Net Income (1) (2)	$	346			$	320		$	310		$	320		$	257		$	273		$	245		$	234		$	258		$	232
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions)		117.0				116.7			115.8			113.8			111.6			n/a			n/a			n/a			n/a			n/a
Basic and Diluted Earnings Per Share (1)(2)	$	2.95			$	2.74		$	2.68		$	2.81		$	2.30			n/a			n/a			n/a			n/a			n/a
Dividends Declared Per Share of Common Stock	$	1.84			$	1.76		$	1.68		$	1.56		$	1.46			n/a			n/a			n/a			n/a			n/a
Balance Sheet Data
Utility Plant, Net	$	8,305			$	7,538		$	7,007		$	6,734		$	6,762		$	6,905		$	6,202		$	5,748		$	5,580		$	5,621
Total Assets		11,502				10,165			9,817			9,519			9,006			9,052			7,977			7,626			7,366			6,985
Capitalization:
Common equity	$	3,045			$	2,960		$	2,846		$	2,677		$	2,451		$	2,704		$	2,622		$	2,457		$	2,362		$	2,164
Preferred Stock (Not subject to purchase or sinking funds)		106				106			106			106			106			106			106			106			106			106
Preferred Stock, net (Subject to purchase or sinking funds)		7				7			8			8			9			7			7			8			8			9
Long-term Debt, net		4,361				2,879			3,067			2,948			3,186			3,033			2,003			2,008			1,856			1,981
Total Capitalization	$	7,519			$	5,952		$	6,027		$	5,739		$	5,752		$	5,850		$	4,738		$	4,579		$	4,332		$	4,260
Other Statistics
Electric:
Customers (Year-End)		649,571				639,258			623,402			609,971			591,435			649,636			639,312			623,453			610,025			591,497
Total sales (Million KWh)		24,284				24,885			24,519			25,305			25,027			24,287			24,888			24,538			25,323			25,046
Generating capability-Net MW (Year-End)		5,695				5,749			5,749			5,808			5,817			5,695			5,749			5,749			5,808			5,817
Territorial peak demand-Net MW		4,789				4,926			4,742			4,820			4,574			4,789			4,926			4,742			4,820			4,574
Regulated Gas:
Customers, excluding transportation (Year-End)		774,502				759,336			738,317			716,794			693,172			307,074			302,469			297,165			291,607			284,355
Sales, excluding transportation (Thousand Therms) (3)		848,568				823,976			997,173			1,106,526			1,124,555			416,075			407,204			403,489			410,700			399,601
Transportation customers (Year-End) (3)		474				446			430			365			474			120			115			100			97			110
Transportation volumes (Thousand Therms) (3)		1366,675,				1,369,684			852,100			707,189			640,229			64,034			27,113			24,845			20,317			22,725
Retail Gas Marketing:
Retail customers (Year-End)		459,250				484,565			482,822			479,382			472,468			n/a			n/a			n/a			n/a			n/a
Firm customer deliveries (Thousand Therms)		356,288				340,743			335,896			379,913			379,712			n/a			n/a			n/a			n/a			n/a
Nonregulated interruptible customer deliveries (Thousand Therms)		1,526,933				1,548,878			1,239,926			1,010,066			917,875			n/a			n/a			n/a			n/a			n/a

(1) In 2006, includes a reduction of an accrual upon settlement of certain litigation associated with SCANA’s prior sale of its

propane assets of $4.7 million.

(2) Reflects the 2006 adoption of SFAS 123(R), recorded as the cumulative effect of

an accounting change of $6 million for SCANA and $4 million for SCE&G.

(3) Reflects the change in business model of CGTC from an intrastate supplier of natural gas to a transportation-only,

interstate pipeline company in November 2006.

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SCANA CORPORATION

			Page

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		28
		Overview	28
		Results of Operations	31
		Liquidity and Capital Resources	36
		Environmental Matters	41
		Regulatory Matters	44
		Critical Accounting Policies and Estimates	44
		Other Matters	47

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		47

Item 8.	Financial Statements and Supplementary Data		50
		Report of Independent Registered Public Accounting Firm	50
		Consolidated Balance Sheets	51
		Consolidated Statements of Income	53
		Consolidated Statements of Cash Flows	54
		Consolidated Statements of Changes in Common Equity and Comprehensive Income	55
		Notes to Consolidated Financial Statements	56

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

OF OPERATIONS

OVERVIEW

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

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

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The following percentages reflect revenues and net income earned by the Company’s regulated and nonregulated businesses and the percentage of total assets held by them.

% of Revenues (a)	2008			2007			2006
Regulated		65	%		66	%		69	%
Nonregulated		35	%		34	%		31	%

% of Net Income (b)
Regulated		94	%		92	%		89	%
Nonregulated		6	%		8	%		11	%

% of Assets
Regulated		93	%		92	%		93	%
Nonregulated		7	%		8	%		7	%

(a) In 2006, revenues reflect the prior business model for the Gas Transmission segment. See Results of Operations

for more information.

(b) In 2006, net income for non-regulated businesses included a reduction of an accrual upon settlement of certain

litigation associated with the Company’s prior sale of its propane assets. See Results of Operations for more information.

Key Earnings Drivers and Outlook

The southeast has suffered from the effects of a recession that has progressively worsened during 2008. At December 31, 2008 preliminary estimates of unemployment for the states in which the Company provides service have ranged from 8.1% in Georgia to 9.5% in South Carolina. While customer growth remained positive throughout 2008 in most regulated business segments, the rate of growth slowed considerably. In addition, the regulated business segments began to experience declines in customer usage in 2008. Our nonregulated natural gas marketer experienced a reduction in retail customers of approximately 5% during the year due primarily to intensified competition. The Company expects the recession to continue well into 2009, if not longer, and cannot determine when or if customer growth and usage trends may return to pre-2008 levels.

Over the next five years, key earnings drivers for the Company will be additions to rate base at South Carolina Electric & Gas Company (SCE&G), Carolina Gas Transmission Corporation (CGTC) and Public Service Company of North Carolina, Incorporated (PSNC Energy), consisting primarily of capital expenditures for environmental facilities, new generating capacity and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage in each of the regulated utility businesses, earnings in the natural gas marketing business in Georgia and the level of growth of operation and maintenance expenses.

Electric Operations

The electric operations segment is comprised of the electric operations of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 2008 SCE&G provided electricity to 649,600 customers in an area covering nearly 16,000 square miles. GENCO owns a coal-fired generation station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowance requirements.

Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity may not exceed 11.0%. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers' bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

In 2008, SCE&G contracted with Westinghouse Electric Company LLC and Stone & Webster, Inc. for the design and construction of two 1,117-megawatt nuclear electric generating units at the site of V. C. Summer Nuclear Station (Summer Station). SCE&G and South Carolina Public Service Authority (Santee Cooper) will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent. Assuming timely receipt of federal and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. The successful completion of the project would result in an increase of the Company’s utility plant in service of approximately 60% over its 2008 level. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.

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On February 11, 2009 the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA), seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order, relating to proposed construction by SCE&G and Santee Cooper to build and operate two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement and construction contract under which they will be built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with the schedules, estimates and projections, including contingencies set forth in the approved application. In addition, beginning with the initial proceeding, SCE&G will be allowed to file revised rates with the SCPSC each year to incorporate any nuclear construction work in progress incurred. Requested rate adjustments would be based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. On February 11, 2009 the SCPSC approved the initial rate increase of $7.8 million or 0.4% related to recovery of the cost of capital on project expenditures through June 30, 2008.

On March 31, 2008, SCE&G submitted a combined construction and operating license (COL) application to the Nuclear Regulatory Commission (NRC). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. On September 26, 2008 the NRC issued a thirty month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC continue to be in progress and should support a COL issuance by July 2011. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.

The Company expects that significant legislative or regulatory initiatives will be undertaken, particularly at the federal level. These initiatives may require the Company to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under a renewable portfolio standard or “RPS”). New legislation or regulations may also impose stringent requirements on existing power plants to reduce emissions of sulfur dioxide, nitrogen oxides and mercury. It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. The Company cannot predict whether such legislation or regulations will be enacted, and if they are, the conditions they would impose on utilities.

Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy and is primarily engaged in the purchase, transmission and sale of natural gas to retail customers in portions of North Carolina and South Carolina. At December 31, 2008 this segment provided natural gas to 775,000 customers in areas covering 35,000 square miles.

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

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

Gas Transmission

CGTC operates an open access, transportation-only interstate pipeline company regulated by the United States Federal Energy Regulatory Commission (FERC). CGTC’s operating results are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Demand for CGTC’s services is closely linked to demand for natural gas and is affected by the price of alternate fuels and customer growth. CGTC provides transportation services to SCE&G for its gas distribution customers and for certain electric generation needs and to SCANA Energy Marketing, Inc. (SEMI) for natural gas marketing. CGTC also provides transportation services to other natural gas utilities, municipalities and county gas authorities and to industrial customers.

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Retail Gas Marketing

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to approximately 460,000 customers (as of December 31, 2008, and including regulated division customers described below) throughout Georgia. SCANA Energy’s total customer base represents approximately a 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. SCANA Energy’s competitors include affiliates of other large energy companies with experience in Georgia’s energy market, as well as several electric membership cooperatives. SCANA Energy’s ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors.

As Georgia’s regulated provider, SCANA Energy serves low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the Georgia Public Service Commission (GPSC), and it receives funding from the Universal Service Fund to help offset some of the bad debt associated with the low-income group. SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas ends on August 31, 2009. Two marketers, including SCANA Energy, have made a bid with the GPSC to be the regulated service provider after SCANA Energy’s current contract expires. SCANA Energy expects a decision in March 2009. SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us. At December 31, 2008, SCANA Energy’s regulated division served over 90,000 customers.

SCANA Energy and SCANA’s other natural gas distribution and marketing segments maintain gas inventory and also utilize forward contracts and other financial instruments, including commodity swaps and futures contracts, to manage their exposure to fluctuating commodity natural gas prices. See Note 9 to the consolidated financial statements. As a part of this risk management process, at any given time, a portion of SCANA’s projected natural gas needs has been purchased or otherwise placed under contract. Since SCANA Energy operates in a competitive market, it may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability. Further, there can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve.

Energy Marketing

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

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

RESULTS OF OPERATIONS

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

	2008		2007		2006
Reported (GAAP) earnings per share	$	2.95	$	2.74	$	2.68
Deduct:
Cumulative effect of accounting change, net of tax		-		-		(.05	)
Reduction in charge related to propane litigation		-		-		(.04	)
GAAP-adjusted net earnings from operations per share	$	2.95	$	2.74	$	2.59
Cash dividends declared (per share)	$	1.84	$	1.76	$	1.68

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Discussion of above adjustments:

The cumulative effect of an accounting change resulted from the Company’s adoption of Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)). The reduction in charge related to propane litigation resulted from litigation arising from the prior sale of the Company’s propane business being settled for an amount that was less than had been accrued previously. This reduction appears in the income statement as a reduction to other expenses.

Management believes that these adjustments are appropriate in determining the non-GAAP financial performance measure. Management utilizes such measure in exercising budgetary control, managing business operations and determining eligibility for certain incentive compensation payments. The non-GAAP measure, GAAP-adjusted net earnings per share from operations, provides a consistent basis upon which to measure performance by excluding the cumulative effect on per share earnings of the accounting change resulting from the Company’s adoption of SFAS 123(R) and the effect on per share earnings of litigation related to the sale of a prior business.

Pension Income

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

Millions of dollars	2008		2007		2006
Income Statement Impact:
Reduction in employee benefit costs	$	0.6	$	2.5	$	0.7
Other income		14.6		13.7		12.3
Balance Sheet Impact:
Reduction in capital expenditures		0.3		0.8		0.3
Component of amount due to Summer Station co-owner		0.3		0.4		0.2
Total Pension Income	$	15.8	$	17.4	$	13.5

The Company expects to record significant amounts of pension expense in 2009 compared to the pension income recorded in 2008. This unfavorable change is expected due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets. However, the Company does not expect that a contribution to the pension trust will be necessary in or for 2009, nor does the Company expect limitations on benefit payments to apply. Additionally, in February 2009, the Company was granted accounting orders by the SCPSC which will allow it to mitigate a significant portion of this increased pension expense by deferring as a regulatory asset the amount of pension expense above that which is included in current rates for both of the Company’s South Carolina regulated businesses. These costs will be deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively. See further information at Liquidity and Capital Resources and Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 5.6% of income before income taxes in 2008, 3.3% in 2007 and 2.0% in 2006.

Electric Operations

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

Millions of dollars	2008		% Change			2007		% Change			2006
Operating revenues	$	2,236.4		14.4	%	$	1,954.1		4.1	%	$	1,877.6
Less: Fuel used in generation		863.6		30.4	%		662.3		7.7	%		615.1
Purchased power		36.1		10.4	%		32.7		18.9	%		27.5
Margin	$	1,336.7		6.2	%	$	1,259.1		2.0	%	$	1,235.0

•

2008 vs 2007

Margin increased by $74.5 million due to increased retail electric rates that went into effect in January 2008 and by $16.6 million due to residential and commercial customer growth. These increases were offset by $5.4 million due to lower off-system sales, by $3.5 million due to lower industrial sales and $10.0 million in lower residential and commercial usage.

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2007 vs 2006

Margin increased by $27.3 million due to customer growth and usage and due to other electric revenue of $5.2 million. These increases were offset by lower off-system sales of $10.2 million.

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

Classification (in thousands)	2008		% Change			2007		% Change			2006
Residential		7,828		0.2	%		7,814		2.8	%		7,598
Commercial		7,450		(0.3	)%		7,469		3.0	%		7,249
Industrial		6,152		(1.8	)%		6,267		1.4	%		6,183
Sales for resale (excluding interchange)		1,850		(11.9	)%		2,100		1.2	%		2,076
Other		569		1.1	%		563		6.8	%		527
Total territorial		23,849		(1.5	)%		24,213		2.5	%		23,633
Negotiated Market Sales Tariff (NMST)		435		(35.3	)%		672		(24.2	)%		886
Total		24,284		(2.4	)%		24,885		1.5	%		24,519

•

2008 vs 2007

Territorial sales volumes decreased by 252 MWh due to weather and by 115 MWh due to lower industrial sales volumes as a result of a slowing economy, partially offset by an increase of 238 MWh due to residential and commercial customer growth.

•

2007 vs 2006

Territorial sales volumes increased by 343 MWh primarily due to residential and commercial customer growth and by 83 MWh due to higher industrial sales volumes.

Gas Distribution

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

Millions of dollars	2008		% Change			2007		% Change			2006
Operating revenues	$	1,238.1		12.9	%	$	1,096.4		1.7	%	$	1,078.0
Less: Gas purchased for resale		886.1		15.9	%		764.6		(2.9	)%		787.1
Margin	$	352.0		6.1	%	$	331.8		14.1	%	$	290.9

•

2008 vs 2007

Margin increased by $3.6 million due to an SCPSC-approved increase in retail gas base rates at SCE&G which became effective with the first billing cycle of November 2007, by $1.1 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2008, and by $2.4 million due to other customer growth at SCE&G. The NCUC-approved rate increase at PSNC Energy, for services rendered on or after November 1, 2008, increased margin by $2.5 million, while an increase in normalized customer usage contributed $5.0 million and customer growth added $4.9 million.

•

2007 vs 2006

Margin increased by $13.6 million due to an SCPSC-approved increase in retail gas base rates at SCE&G which became effective with the first billing cycle of November 2006, by $1.0 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2007, and by $6.1 million due to other customer growth at SCE&G. The NCUC - approved rate increase at PSNC Energy, for services rendered on or after November 1, 2006, increased margin by $14.3 million. The increase in margin at PSNC Energy also reflects customer growth in 2007 and significant conservation in 2006 due to high natural gas prices.

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

Classification (in thousands)	2008		% Change			2007		% Change			2006
Residential		37,507		8.6	%		34,544		5.1	%	32,879
Commercial		28,004		5.4	%		26,573		3.3	%	25,718
Industrial		19,345		(9.1	)%		21,281		0.3	%	21,209
Transportation gas		35,124		12.7	%		31,154		3.3	%	30,147
Total		119,980		5.7	%		113,552		3.3	%	109,953

•

2008 vs 2007

Residential, commercial and transportation gas sales volume increased primarily due to customer growth. Industrial gas sales volume decreased primarily due to a loss of customers as a result of a slowing economy.

•

2007 vs 2006

Residential, commercial and transportation gas sales volumes increased primarily due to customer growth.

Gas Transmission

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

Millions of dollars	2008		% Change		2007		% Change			2006
Transportation revenue	$	49.1		-	$	49.1		85.3	%	$	26.5
Other operating revenues		-		-		-		*			475.0
Less: Gas purchased for resale		-		-		-		*			439.2
Margin	$	49.1		-	$	49.1		(21.2	)%	$	62.3

*Change not meaningful due to change to a transportation-only business model.

•

2008 vs 2007

Transportation revenue is based upon contracts to reserve long-term capacity and is not dependent upon volumes. In 2008 the transportation revenue was unchanged from 2007.

•

2007 vs 2006

Transportation revenue increased as a result of the change to an open access, transportation-only interstate pipeline company effective November 1, 2006. As a result of this change, CGTC no longer earns commodity gas revenues, nor does it incur gas costs.

Transportation volumes totaled 107.9 million DT in 2008 and 108.6 million DT in 2007. Transportation volumes decreased during such period as a result of lower generation, primarily due to milder weather and a slowing economy. In 2006, transportation volumes totaled 57.5 million DT, and sales volumes for all commercial, industrial and sales for resale customers totaled 52.2 million DT. Volumes in 2006 are not comparable to 2007 due to CGTC’s change to an open access, transportation-only interstate pipeline company effective November 1, 2006.

Retail Gas Marketing

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

Millions of dollars	2008		% Change			2007		% Change			2006
Operating revenues	$	631.7		8.1	%	$	584.2		(3.9	)%	$	608.1
Net income		32.5		18.2	%		27.5		(8.6	)%		30.1

•

2008 vs 2007

Operating revenues increased primarily as a result of higher average retail prices and volumes. Net income increased primarily due to higher margin and lower bad debt expense, partially offset by the GPSC settlement.

•

2007 vs 2006

Operating revenues decreased primarily due to lower average retail prices. Net income decreased primarily due to higher expenses, including bad debt expense.

Delivered volumes totaled 35.6 million DT in 2008, 34.1 million DT in 2007 and 33.6 million DT in 2006.

Energy Marketing

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

Millions of dollars	2008		% Change			2007		% Change			2006
Operating revenues	$	1,483.8		27.1	%	$	1,167.7		23.1	%	$	948.7
Net income (loss)		1.9		(32.1	)%		2.8		*			(0.4	)

*Greater than 100%.

•

2008 vs 2007

Operating revenues increased primarily due to higher market prices which more than offset the decrease in sales volumes. Net income decreased due to higher operating expenses.

•

2007 vs 2006

Operating revenues increased primarily due to customer growth, some of which results from sales to customers formerly reported in the Gas Transmission segment now being reported in Energy Marketing. Net income increased due to higher margin on sales of $3.8 million, offset by higher operating expenses of $1.0 million.

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Delivered volumes totaled 152.6 million DT in 2008, 154.9 million DT in 2007 and 123.9 million DT in 2006. Delivered volumes decreased in 2008 compared to 2007 primarily as a result of decreased sales due to milder weather. Delivered volumes increased in 2007 compared to 2006 primarily as a result of customer growth, including sales to customers formerly reported in the Gas Transmission segment.

Other Operating Expenses

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

Millions of dollars	2008		% Change			2007		% Change			2006
Other operation and maintenance	$	674.6		4.1	%	$	648.2		4.7	%	$	619.2
Depreciation and amortization		319.3		(1.3	)%		323.4		(2.7	)%		332.4
Other taxes		168.0		4.9	%		160.2		5.5	%		151.8
Total	$	1,161.9		2.7	%	$	1,131.8		2.6	%	$	1,103.4

•

2008 vs 2007

Other operation and maintenance expenses increased by $2.6 million due to higher generation, transmission and distribution expenses, by $8.9 million due to higher incentive compensation and other benefits, by $6.4 million due to higher customer service expense, including bad debt expense, by $2.0 million due to lower pension income and $2.6 million due to increased legal expenses related to SCANA Energy’s settlement with the GPSC. Depreciation and amortization expense decreased by $4.6 million due to the 2007 expiration of the synthetic fuel tax credit program (see Income Taxes - Recognition of Synthetic Fuel Tax Credits) and by $8.5 million due to the 2007 expiration of a three-year amortization of previously deferred purchase power costs, partially offset by $10.3 million due to 2008 net property additions. Other taxes increased primarily due to higher property taxes.

•

2007 vs 2006

Other operation and maintenance expenses increased by $4.6 million due to higher generation, transmission and distribution expenses, by $19.7 million due to higher incentive compensation and other benefits and by $4.7 million due to higher bad debt expense at Retail Gas Marketing. Depreciation and amortization expense decreased by $19.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2007 compared to 2006 (see Income Taxes - Recognition of Synthetic Fuel Tax Credits), partially offset by $11.4 million due to 2007 net property additions. Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

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

Millions of dollars		2008		% Change				2007		% Change				2006
Other revenues	$	78.6			(21.2	)%	$	99.8			(31.2	)%	$	145.0
Other expenses		(41.5	)		(13.9	)%		(48.2	)		(48.2	)%		(93.1	)
Total	$	37.1			(28.1	)%	$	51.6			(0.6	)%	$	51.9

* Greater than 100%

•

2008 vs 2007

Other revenues decreased by $11.7 million and other expenses decreased by $6.7 million due to management and maintenance services no longer being provided for a non-affiliated synthetic fuel production facility. Other revenues also decreased by $5.8 million due to income from the sale of a bankruptcy claim in 2007.

•

2007 vs 2006

Other revenues decreased by $32.0 million due to lower power marketing activities and by $26.6 million due to lower fees received for management and maintenance services for a non-affiliated synthetic fuel production facility, as discussed at Income Taxes-Recognition of Synthetic Fuel Tax Credits below. These decreases were partially offset by $5.8 million related to the sale of a bankruptcy claim and by $1.9 million due to lower partnership losses, also as discussed at Income Taxes- Recognition of Synthetic Fuel Tax Credits below.

Other expenses decreased $31.2 million due to lower power marketing activities, by $19.4 million due to lower management service expenses incurred, as discussed at Income Taxes-Recognition of Synthetic Fuel Tax Credits below and by $8.7 million related to a FERC power marketing settlement in 2006. These decreases were partially offset by $7.6 million related to the settlement of propane litigation in 2006.

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Interest Expense

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

Millions of dollars	2008		% Change			2007		% Change			2006
Interest on long-term debt, net	$	212.1		21.5	%	$	174.5		(8.6	)%	$	190.9
Other interest expense		15.2		(52.2	)%		31.8		70.1	%		18.7
Total	$	227.3		10.2	%	$	206.3		(1.6	)%	$	209.6

•

2008 vs 2007

Interest on long-term debt increased primarily due to increased long-term borrowings. Other interest expense decreased primarily due to lower principal balances on short-term debt.

•

2007 vs 2006

Interest on long-term debt decreased primarily due to reduced long-term borrowings and lower interest rates. Other interest expense increased primarily due to higher principal balances and interest rates on short-term debt.

Income Taxes

Income tax expense increased primarily due to the recognition at SCE&G of $17.4 million in synthetic fuel tax credits in 2007 and due to changes in operating income. The recognition of these tax credits in 2006 was $33.5 million.

Recognition of Synthetic Fuel Tax Credits

SCE&G held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel, the use of which fuel qualified for federal income tax credits. Under an accounting methodology approved by the SCPSC, construction costs related to the Lake Murray back-up dam project were recorded in utility plant in service in a special dam remediation account, outside of rate base, and accelerated depreciation was recognized against the balance in this account, subject to the availability of the synthetic fuel tax credits. The synthetic fuel tax credit program expired at the end of 2007.

For 2007 and 2006, the level of depreciation expense and related tax benefit recognized in the income statement was equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account declined as accelerated depreciation was recorded. Although these entries collectively had no impact on consolidated net income, they did impact individual line items within the income statement, as follows:

Millions of dollars		2007		2006
Depreciation and amortization expense	$	(8.4	)	$	(28.2	)
Income tax benefits		26.9			48.6
Losses from Equity Method Investments		(18.5	)		(20.4	)
Impact on Net Income	$	-		$	-

Available credits were not sufficient to fully recover the construction costs of dam remediation; therefore, regulatory action to allow recovery of remaining costs will be sought. In addition, SCE&G records non-cash carrying costs on the unrecovered investment which amounts were $5.5 million in 2008, $5.6 million in 2007 and $6.6 million in 2006. As of December 31, 2008, remaining unrecovered costs were $70.0 million and were recorded as a regulatory asset within Utility Plant. The Company expects these costs to be recoverable through rates.

SCANA, through a subsidiary, provided management and maintenance services for a non-affiliated synthetic fuel production facility. These services ceased on December 31, 2007, concurrent with the expiration of the synthetic fuel tax credit program.

LIQUIDITY AND CAPITAL RESOURCES

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

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Challenging conditions during 2008 tested the Company’s liquidity and its ability to access short-term funding sources. During this period, all of the banks in the Company’s revolving credit facilities fully funded draws requested of them. As of December 31, 2008, the Company had drawn approximately $450 million from its $1.1 billion facilities, had approximately $80 million in commercial paper borrowings outstanding and approximately $250 million in cash and temporary investments. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.

At December 31, 2008, the Company had net available liquidity of approximately $800 million, and the Company’s revolving credit facilities are in place until December 2011. The Company’s overall debt portfolio has weighted average maturity of over thirteen years and bears an average cost of 5.62%. All long-term debt, other than facility draws, bears fixed interest rates. To further preserve liquidity, the Company rigorously reviewed its projected capital expenditures and operating costs for 2009 and adjusted them where possible without impacting safety, reliability, and core customer service.

The Company also obtains cash from SCANA’s stock plans. Since July 1, 2008, shares of SCANA common stock purchased on behalf of participants in SCANA’s Investor Plus Plan and Stock Purchase-Savings Plan have been acquired through original issue shares, rather than on the open market. This provided over $40 million of additional cash during 2008 and is expected to provide approximately $80 million annually for 2009 and forward. Due primarily to new nuclear construction plans, the Company anticipates keeping this strategy in place for the foreseeable future.

On January 7, 2009, SCANA closed on the sale of 2.875 million shares of its common stock, raising approximately $100 million. With the reduction of capital expenditures planned for 2009 and planned operating cost reductions in response to current economic conditions, this transaction makes it unlikely that SCANA will need to raise additional equity in 2009 beyond that issued through SCANA’s stock plans.

SCANA's leverage ratio of debt to capital was approximately 59% at December 31, 2008. SCANA has publicly announced its desire to achieve a leverage ratio at 54% to 57%, but SCANA's ability to do so depends on a number of factors. If SCANA is not able to maintain its leverage ratio, the Company's debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.

Capital Expenditures

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $904 million in 2008 and are estimated to be $1.2 billion in 2009.

The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2009-2011, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars	2009		2010		2011
SCE&G:
Electric Plant:
Generation (including GENCO)	$	652	$	758	$	897
Transmission		48		46		68
Distribution		178		184		190
Other		40		22		21
Nuclear Fuel		43		78		59
Gas		53		60		59
Common and other		39		16		17
Total SCE&G		1,053		1,164		1,311
Other Companies Combined		185		109		107
Total	$	1,238	$	1,273	$	1,418

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The Company’s contractual cash obligations as of December 31, 2008 are summarized as follows:

Contractual Cash Obligations

	Payments due by periods
Millions of dollars		Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long- and short-term debt (including
interest and preferred stock redemptions)		$	8,087	$	522	$	2,015	$	542	$	5,008
Capital leases			3		2		1		-		-
Operating leases			50		18		21		4		7
Purchase obligations			707		689		18		-		-
Other commercial commitments			6,922		1,414		2,320		981		2,207
Total		$	15,769	$	2,645	$	4,375	$	1,527	$	7,222

Not included in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of V. C. Summer Nuclear Station (Summer Station). SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent. Assuming timely receipt of federal and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. SCE&G’s share of the estimated cash outlays, including contractual amounts not reflected above, are as follows:

Future Value
Millions of dollars	2009		2010		2011		2012		2013		After 2013		Total
Plant Costs	$	472	$	648	$	766	$	734	$	752	$	1,929	$	5,301
Transmission Costs		1		2		5		2		16		620		646

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

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

In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no required contributions are anticipated until after 2010. Cash payments under the health care and life insurance benefit plan were $11.1 million in 2008, and such annual payments are expected to increase to the $12-$13 million range in the future.

In addition, the Company is party to certain New York Mercantile Exchange (NYMEX) futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk. At December 31, 2008, the Company had posted $4.2 million in cash collateral for such contracts.

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

The Company does not have any recorded or unrecorded obligations under the provisions of Financial Accounting Standards Board Interpretation (FIN) 48, “Accounting for Uncertainty in Income Taxes.”

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

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Financing Limits and Related Matters

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

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of short-term indebtedness. The authority to make such issuances will expire on February 6, 2010.

At December 31, 2008, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the lines of credit and outstanding borrowings under or supported by such lines of credit, as follows:

Millions of dollars	SCANA			SCE&G			PSNC Energy
Lines of Credit:
Committed long-term (expire December 2011)
Total	$	200		$	650		$	250
Outstanding bank loans		15			285			156
Weighted average interest rate		2.17	%		1.61	%		1.72	%
Outstanding commercial paper (270 or fewer days) (a)		-			34			46
Weighted average interest rate		-			5.69	%		6.15	%
Uncommitted (b):
Total	$	78		$	-		$	-
Used		-			-			-
Weighted average interest rate		-			-			-

(a) The Company’s committed lines of credit serve to backup the issuance of commercial paper.

(b) SCANA, SCE&G or a combination may use the line of credit.

The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wachovia Bank, National Association and Bank of America, N. A. each provide 14.3% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%. Four other banks provide the remaining 9.6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company) and PSNC Energy. In addition, a portion of the credit facilities supports SCANA’s borrowing needs. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company) and PSNC Energy.

In mid-September 2008, a very severe dislocation of the commercial paper, long-term debt and equity markets occurred as concerns over bank solvency adversely impacted the credit markets. Access by SCE&G, Fuel Company and PSNC Energy to the commercial paper markets was very limited. Commercial paper outstanding was significantly reduced, and the interest rates on commercial paper outstanding significantly increased. Generally, SCE&G, Fuel Company and PSNC Energy were only able to issue commercial paper for one week terms, much shorter periods than their prior customary one month terms. In response to the credit market disruption, the Federal Reserve created a Commercial Paper Funding Facility (CPFF) to provide liquidity to the commercial paper market by increasing the availability of funding to certain commercial paper issuers. However, the CPFF, which became active in the market on October 27, 2008, only provides such funding to issuers of Tier 1 commercial paper (issuers with credit ratings of A1, P1, F1). While SCE&G, Fuel Company and PSNC Energy, as Tier 2 issuers (with credit ratings of A2, P2, F2), do not qualify for the CPFF program, the Company expected that, over time, the enhanced liquidity in the Tier 1 commercial paper market would positively affect the Tier 2 commercial paper market. As a result of the limited access to commercial paper, SCE&G, Fuel Company and PSNC Energy accessed their credit facilities with banks (described above) and drawn down funds to replace maturing commercial paper. Since year-end, access to the commercial paper market has improved and interest rates have declined significantly. Although these improvements in the commercial paper market have occurred, draws against the revolving credit facilities have been maintained as the interest rates on these draws continue to remain favorable.

Access to the debt capital markets was also very limited. SCE&G took advantage of a narrow window of market opportunity and issued $300 million of its First Mortgage Bonds at a coupon of 6.50% on October 2, 2008. Issuers found limited opportunities to issue secured long-term debt and only at increased interest rates. Since year-end, however, as the equity markets have deteriorated, the capital markets, particularly in secured long-term bonds of utility companies, have improved. Currently, opportunities to issue unsecured long-term debt still appear to be more limited, although improved since year-end.

The Company cannot determine how long this dislocation of the credit markets will last. The Company expects that the risks of a global recession may continue to hamper the economy and adversely affect the capital markets.

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

SCANA Corporation

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

South Carolina Electric & Gas Company

SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its First Mortgage Bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, will be issuable under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2008, the Bond Ratio was 5.51.

SCE&G’s Restated Articles of Incorporation (Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders unless net earnings (as therein defined) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half (1.5) 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, 2008, the Preferred Stock Ratio was 1.7.

The Articles also require the consent of a majority of the total voting power of SCE&G’s preferred stock before SCE&G may issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed ten percent of the aggregate principal amount of all of SCE&G’s secured indebtedness and capital and surplus (the Ten Percent Test). No such consent is required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes. At December 31, 2008, the Ten Percent Test would have limited total issuances of unsecured indebtedness to approximately $526.1 million. Unsecured indebtedness at December 31, 2008, totaled $222.0 million, and comprised both long- and short-term borrowings.

Financing Activities

During 2008 the Company experienced net cash inflows related to financing activities of $571 million primarily due to issuances of long-term debt and common stock, partially offset by repayment of short-term debt and payment of dividends.

In June 2007 SCANA entered into an agreement to issue and sell Floating Rate Senior Notes due June 1, 2034, in an aggregate principal amount of between $90 million and $110 million. In each of December 2008 and 2007 SCANA issued $40 million of the Floating Rate Senior Notes. The balance of the notes are to be issued in June 2009. In the fourth quarter of 2008 SCANA entered into a forward starting swap agreement with a notional amount of $20 million in anticipation of the June 2009 issuance. At December 31, 2008 the estimated fair value of the forward starting interest rate swap totaled $2.8 million (loss).

On January 14, 2008, SCE&G issued $250 million of First Mortgage Bonds bearing an annual interest rate of 6.05% and maturing on January 15, 2038. Proceeds from the sale of these bonds were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program and for general corporate purposes. Concurrent with this issuance, SCE&G terminated 30-year forward-starting swaps having an aggregate notional amount of $250 million. The resulting loss of approximately $14.0 million on the settlement of these swaps will be amortized over the life of the bonds.

On March 12, 2008, SCANA issued $250 million of Medium Term Notes bearing an annual interest rate of 6.25% and maturing on April 1, 2020. Proceeds from the sale of these notes were used to repay short-term debt incurred to pay at maturity on March 1, 2008 $100 million of floating rate Medium Term Notes, to pay at maturity on October 23, 2008 $115 million of Medium Term Notes, to repay other short-term debt and for general corporate purposes. Concurrent with this issuance, SCANA terminated a treasury lock having a notional amount of $250 million. The resulting loss on the treasury lock of approximately $3.1 million will be amortized over the life of the Medium Term Notes.

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On May 30, 2008, GENCO issued $80 million in notes bearing an annual interest rate of 6.06% and maturing on June 1, 2018. Proceeds from the sale of the notes were used to repay short-term debt primarily incurred as a result of GENCO’s construction program. On October 1, 2008, GENCO issued an additional $80 million of notes with the same terms.

On June 24, 2008, SCE&G issued $110 million of First Mortgage Bonds bearing an annual interest rate of 6.05% and maturing on January 15, 2038. Proceeds from the sale of these bonds were used to repay short term debt and for general corporate purposes. Concurrent with this issuance, SCE&G terminated a treasury lock having a notional amount of $110 million. The resulting gain of approximately $0.5 million will be amortized over the life of the bonds.

On October 2, 2008, SCE&G issued $300 million of First Mortgage Bonds bearing an annual interest rate of 6.50% and maturing on November 1, 2018. Proceeds from the sale of these bonds were used to repay short-term debt and for general corporate purposes.

On November 14, 2008, GENCO became obligated with respect to $36.4 million of tax-exempt Industrial Revenue Bonds. These bonds have a floating interest rate, although the major component of the interest rate on the bonds is hedged by a pay fixed, receive variable interest rate swap that results in a fixed rate on that component of 3.68%. On December 10, 2008, SCE&G became obligated with respect to $35 million of tax-exempt Industrial Revenue Bonds having a similar swap that results in a fixed rate on that component of 2.89%. These bonds mature on December 1, 2038. Both bond issues are supported by bank letters of credit with stated expiration dates (subject to early termination) of November 14, 2009 and December 10, 2011, respectively. See Note 5 to the consolidated financial statements of SCANA and SCE&G.

On January 7, 2009, SCANA closed on the sale of 2.875 million shares of common stock at $35.50 per share. Proceeds to SCANA were $100.5 million and will be used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.

In the fourth quarter of 2008 SCE&G entered into a forward starting swap agreement in anticipation of the issuance of First Mortgage Bonds with a tenure of 30 years. At December 31, 2008, the estimated fair value of the Company’s forward starting swap totaled $43.7 million (loss) related to a notional amount of $150 million.

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

On February 19, 2009, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.47 per share, an increase of 2.0%. The new dividend is payable April 1, 2009 to stockholders of record on March 10, 2009.

ENVIRONMENTAL MATTERS

The Company’s regulated operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the Clean Air Act, as amended (CAA), the Clean Air Interstate Rule (CAIR), the Clean Water Act, the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), among others. Compliance with these environmental requirements involves significant capital and operating costs, which the Company expects to recover through existing ratemaking provisions.

For the three years ended December 31, 2008, the Company’s capital expenditures for environmental control totaled $526.6 million. These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $44.0 million during 2008, $34.4 million during 2007, and $28.7 million during 2006. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $110.0 million for 2009 and $137.1 million for the four-year period 2010-2013. These expenditures are included in the Company’s Estimated Capital Expenditures table, discussed in Liquidity and Capital Resources, and include the matters discussed below.

In addition, the Company is monitoring federal legislative proposals that, among other things, may require significant reductions in carbon dioxide and other greenhouse gas emissions widely believed to contribute to global climate change. Such legislation could impose a tax based on the carbon content of fossil fuels used by the Company, such as coal and natural gas. Other proposals call for implementation of a cap and trade program as a means of meeting stringent new emissions standards. A national mandatory RPS may also be considered. Under an RPS, electric utilities would be required to generate a specific percentage of their power from sources deemed to be “climate-friendly,” such as solar, wind, geothermal and agricultural waste, over varying periods of time. The Company cannot predict the outcome of these proposals.

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At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2008. The Company cannot predict whether such legislation will be introduced or enacted in 2009, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.

Air Quality

The United States Environmental Protection Agency (EPA) issued a final rule in 2005 known as CAIR. CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule without vacatur. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements, including the installation of selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction and wet limestone scrubbers at both Wateree and Williams Stations for sulfur dioxide reduction. SCE&G and GENCO have already begun to install this equipment, and expect to incur capital expenditures totaling approximately $559 million through 2010. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In 2005 the EPA issued the Clean Air Mercury Rule (CAMR) which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule, and on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. The Company expects the EPA to issue a new mercury emissions rule but cannot predict when such a rule will be issued or what requirements it will impose.

The EPA has undertaken an enforcement initiative against the utilities industry, and the United States Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the CAA. At least two of these suits have either been tried or have had substantive motions decided—neither favorable to the industry. One of the decisions is not believed to be binding as precedent and the other one, described more fully below, may be.

On April 2, 2007, in a unanimous ruling, the U.S. Supreme Court vacated a decision by the U.S. Court of Appeals for the Fourth Circuit that effectively halted the EPA enforcement action against Duke Energy Corporation (Duke) for allegedly performing plant modifications without a required permit. Such modifications for life extension and modernization as performed by Duke and other utilities, including SCE&G, were common within the industry. Hence this decision may heighten the potential exposure of utilities to enforcement actions such as those already brought against Duke and others, many of which had not proceeded pending this Supreme Court decision. The ultimate outcome of this matter cannot be predicted.

Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA, under a stringent rule known as New Source Review (NSR), that maintenance activities undertaken by the utilities over the past 20 or more years constitute “major modifications” which would have required the installation of costly Best Available Control Technology (BACT). SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of “major modifications,” including an exemption for routine repair, replacement or maintenance. On October 27, 2003, EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. The ultimate application of the final rule to the Company is uncertain. The Company has analyzed each of the activities covered by the EPA’s requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth.

The current state of continued DOJ enforcement actions is the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $32,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any enforcement actions relative to the Company compliance with CAA would be without merit. The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the concerns with NSR.

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Water Quality

The Clean Water Act, as amended (CWA), provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all, and renewed for nearly all, of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include limitations to mixing zones and toxicity-based standards. These provisions, if passed, could have a material adverse impact on the financial condition, results of operations and cash flows of the Company, SCE&G and GENCO.

Hazardous and Solid Wastes

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the United States Department of Energy (DOE) in 1983. As of December 31, 2008, the federal government has not accepted any spent fuel from Summer Station or any other utility, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available.

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

Electric Operations

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List in April 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2009. The site has not been remediated nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

Gas Distribution

SCE&G is responsible for four decommissioned manufactured gas plant (MGP) sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control (DHEC). SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $9.5 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates. At December 31, 2008, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

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PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of $4.5 million, the estimated remaining liability at December 31, 2008. PSNC Energy expects to recover through rates any costs, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

REGULATORY MATTERS

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

South Carolina Electric & Gas Company

SCE&G is subject to the jurisdiction of the SEC and FERC as to the issuance of certain securities, acquisitions and other matters.

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.

In May 2007, the statutory definition of fuel costs was revised to include certain variable environmental costs such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The revised definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, and mercury and particulates.

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

Public Service Company of North Carolina, Incorporated

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

The United States Congress passed the Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directing the United States Department of Transportation (DOT) to establish the Integrity Management Rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy’s approximately 593 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 57 miles are located within these areas. Fifty percent of these miles of pipeline were required to be assessed by December 2007, and the remainder by December 2012. Through December 2008, PSNC Energy has assessed eighty-five percent of the pipeline. Depending on the assessment method used, PSNC Energy will be required to reinspect these same miles of pipeline approximately every seven years. Though cost estimates for this program were developed using various assumptions, each of which is subject to imprecision, PSNC Energy currently estimates the total cost through December 2012 to be $7.0 million for the initial assessments, not including any subsequent remediation that may be required. Costs totaling $2.3 million are being recovered through rates over a three-year period beginning November 1, 2008. The NCUC has authorized continuation of deferral accounting for certain expenses incurred to comply with DOT’s pipeline integrity management requirements until resolution of PSNC Energy’s next general rate proceeding.

Carolina Gas Transmission Corporation

CGTC has approximately 73 miles of transmission line that are covered by the Integrity Management Rule of the Pipeline Safety Act. Though cost estimates for this project were developed using various assumptions, each of which is subject to imprecision, CGTC currently estimates the total cost to be $8.3 million for the initial assessments and any subsequent remediation required through December 2012.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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Utility Regulation

SCANA’s regulated utilities are subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” which require them to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations, liquidity or financial position of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. See Note 1B to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2008, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $2.7 billion and $625 million, respectively.

Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of the Company’s utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization or other regulatory provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. Accounts receivable included unbilled revenues of $185.1 million at December 31, 2008 and $175.5 million at December 31, 2007, compared to total revenues of $5.3 billion and $4.6 billion for the years 2008 and 2007, respectively.

Provisions for Bad Debts and Allowances for Doubtful Accounts

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

Nuclear Decommissioning

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

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

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

Accounting for Pensions and Other Postretirement Benefits

The Company follows SFAS 87, “Employers’ Accounting for Pensions,” as amended by SFAS 158, “Employees’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” in accounting for the cost of its defined benefit pension plan. The Company’s plan is adequately funded under current regulations and as such, net pension income is reflected in the financial statements (see Results of Operations-Pension Income). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension income of $15.8 million recorded in 2008 reflects the use of a 6.25% discount rate, derived using a cash flow matching technique, and an assumed 9.00% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 6.00% in 2008 would have increased the Company’s pension income by $0.1 million. Had the assumed long-term rate of return on assets been 8.75%, the Company’s pension income for 2008 would have been reduced by $2.3 million.

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

The Company determines the fair value of a majority of its pension assets utilizing market quotes, with the remaining fair value derived from modeling techniques that incorporate market data.

In developing the expected long-term rate of return assumptions, the Company evaluates historical performance, targeted allocation amounts and expected payment terms. As of the beginning of 2008, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 3.0%, 7.2%, 8.9% and 9.8%, respectively, and the 2008 expected long-term rate of return of 9.0% was based on a target asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2009, the expected rate of return is 8.5%.

As noted in Results of Operations, due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, the Company expects to record significant amounts of pension expense in 2009 compared to the pension income recorded in 2008 and previously. However, in February 2009, the Company was granted accounting orders by the SCPSC which will allow it to mitigate a significant portion of this increased pension expense by deferring as a regulatory asset the amount of pension expense above that which is included in current rates for both of the Company’s South Carolina regulated businesses. These costs will be deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.

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

Similar to its pension accounting, the Company follows SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS 158, in accounting for the cost of its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 6.30%, derived using a cash flow matching technique, and recorded a net SFAS 106 cost of $17.7 million for 2008. Had the selected discount rate been 6.05%, the expense for 2008 would have been $0.2 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.

Asset Retirement Obligations

SFAS 143, “Accounting for Asset Retirement Obligations,” together with Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations,” provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates primarily to the Company’s regulated utility operations, SFAS 143 and FIN 47 have no significant impact on results of operations. As of December 31, 2008, the Company has recorded an ARO of $105 million for nuclear plant decommissioning (as discussed above) and an ARO of $353 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Transactions

Although SCANA invests in securities and business ventures, it does not hold investments in unconsolidated special purpose entities such as those described in SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” or as described in FIN 46(R), “Consolidation of Variable Interest Entities.” SCANA does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, equipment and rail cars.

Claims and Litigation

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

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

	Expected Maturity Date
December 31, 2008 Millions of dollars	2009	2010	2011	2012	2013	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	108.2	14.8	1,075.3	265.5	157.9	2,670.2	4,291.9	4,406.5
Average Fixed Interest Rate (%)	6.27	6.87	4.61	6.23	7.05	5.97	5.70
Variable Rate ($)	26.1	3.2	3.2	3.2	3.2	138.6	177.5	149.1
Average Variable Interest Rate (%)	6.36	2.90	2.90	2.90	2.90	2.14	5.17
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	3.2	3.2			12.8	0.9
Pay Interest Rate (%)	4.66	4.66	4.66	4.66			4.66
Receive Interest Rate (%)	8.75	8.75	8.75	8.75			8.75
Pay Fixed/Receive Variable ($)		3.2	3.2	3.2	3.2	138.6	151.4	(34.3)
Average Pay Interest Rate (%)		6.47	6.47	6.47	6.47	4.83	4.96
Average Receive Interest Rate (%)		2.90	2.90	2.90	2.90	2.14	2.20

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	Expected Maturity Date
December 31, 2007 Millions of dollars	2008	2009	2010	2011	2012	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	123.2	108.2	14.8	619.3	265.5	1,758.1	2,889.1	2,942.5
Average Fixed Interest Rate (%)	5.96	6.27	6.87	6.78	6.23	5.91	6.15
Variable Rate ($)	100.0		1.6	1.6	1.6	35.2	140.0	141.1
Variable Interest Rate (%)	5.27		5.78	5.78	5.78	5.78	5.78
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	3.2	3.2	3.2		16.0	0.6
Pay Interest Rate (%)	8.02	8.02	8.02	8.02	8.02		8.02
Receive Interest Rate (%)	8.75	8.75	8.75	8.75	8.75		8.75
Pay Fixed/Receive Variable ($)			1.6	1.6	1.6	35.2	40.0	(7.2)
Pay Interest Rate (%)			6.47	6.47	6.47	6.47	6.47
Receive Interest Rate (%)			5.78	5.78	5.78	5.78	5.78

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

The above tables exclude long-term debt of $37 million at December 31, 2008 and $72 million at December 31, 2007, which amounts do not have a stated interest rate associated with them.

In June 2007 SCANA entered into an agreement to issue and sell Floating Rate Senior Notes due June 1, 2034, in an aggregate principal amount of between $90 million and $110 million. In each of December 2008 and 2007, SCANA issued $40 million of the Floating Rate Senior Notes. The remainder of the notes are to be issued in June 2009. In the fourth quarter of 2008 SCANA entered into a forward starting swap agreement with a notional amount of $20 million in anticipation of the June 2009 issuance. At December 31, 2008 the estimated fair value of this swap totaled $2.8 million (loss), which is not reflected in the tables above.

In the fourth quarter of 2008, SCE&G entered into a forward starting swap agreement in anticipation of the issuance of future debt. At December 31, 2008, the estimated fair value of the Company’s forward starting swap totaled $43.7 million (loss) related to notional amounts of $150 million, which is not reflected in the tables above.

Commodity Price Risk

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

Expected Maturity:
				Options
	Futures Contracts			Purchased Call	Purchased Put	Purchased Put	Sold Call	Sold Put
2009	Long	Short		(Long)	(Long)	(Short)	(Short)	(Long)
Settlement Price (a)	5.80	8.62	Strike Price (a)	10.14	8.39	8.58	15.24	6.78
Contract Amount (b)	64.8	11.7	Contract Amount (b)	53.3	20.8	11.0	2.6	2.8
Fair Value (b)	43.8	10.9	Fair Value (b)	1.1	(6.8)	3.7	-	(0.6)

2010			Strike Price (a)	9.29	-	-	12.56	6.45
Settlement Price (a)	6.95	-	Contract Amount (b)	7.6	-	-	2.0	1.0
Contract Amount (b)	0.4	-	Fair Value (b)	0.5	-	-	-	(0.1)
Fair Value (b)	0.4	-

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

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Swaps	2009	2010	2011	2012	2013
Commodity Swaps:
Pay fixed/receive variable (b)	177.5	30.9	7.0	4.4	3.7
Average pay rate (a)	8.319	7.939	7.778	7.771	7.845
Average received rate (a)	5.965	7.163	7.325	7.227	7.163
Fair Value (b)	127.3	27.9	6.6	4.1	3.4

Pay variable/receive fixed (b)	5.7	-	-	-	-
Average pay rate (a)	5.639	-	-	-	-
Average received rate (a)	12.656	-	-	-	-
Fair Value (b)	12.8	-	-	-	-

Basis Swaps:
Pay variable/receive variable (b)	79.0	25.1	5.6	3.4	3.4
Average pay rate (a)	6.073	7.162	7.578	7.327	7.253
Average received rate (a)	6.030	7.118	7.530	7.252	7.179
Fair Value (b)	78.4	24.9	5.6	3.4	3.4

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

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 9 to the consolidated financial statements.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

SCANA Corporation:

We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, changes in common equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SCANA Corporation and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/Deloitte & Touche LLP

Columbia, South Carolina

February 27, 2009

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SCANA Corporation

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2008			2007
Assets
Utility Plant In Service	$	10,433		$	9,807
Accumulated Depreciation and Amortization		(3,146	)		(2,981	)
Construction Work in Progress		711			400
Nuclear Fuel, Net of Accumulated Amortization		77			82
Acquisition Adjustments		230			230
Utility Plant, Net		8,305			7,538
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $94 and $84		194			131
Assets held in trust, net-nuclear decommissioning		54			62
Other investments		68			82
Nonutility Property and Investments, Net		316			275
Current Assets:
Cash and cash equivalents		272			134
Receivables, net of allowance for uncollectible accounts of $11 and $10		828			641
Receivables-affiliated companies		-			29
Inventories (at average cost):
Fuel		358			286
Materials and supplies		108			107
Emission allowances		15			33
Prepayments and other		232			62
Deferred income taxes		23			9
Total Current Assets		1,836			1,301
Deferred Debits and Other Assets:
Pension asset, net		-			224
Regulatory assets		905			712
Other		140			115
Total Deferred Debits and Other Assets		1,045			1,051
Total	$	11,502		$	10,165

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December 31, (Millions of dollars)	2008		2007
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	3,045	$	2,960
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		3,151		3,066
Preferred Stock, Net (Subject to purchase or sinking funds)		7		7
Long-Term Debt, Net		4,361		2,879
Total Capitalization		7,519		5,952
Current Liabilities:
Short-term borrowings		80		627
Current portion of long-term debt		144		233
Accounts payable		405		401
Accounts payable-affiliated companies		-		27
Customer deposits and customer prepayments		97		85
Taxes accrued		128		156
Interest accrued		69		51
Dividends declared		56		53
Other		176		88
Total Current Liabilities		1,155		1,721
Deferred Credits and Other Liabilities:
Deferred income taxes, net		1,009		944
Deferred investment tax credits		103		104
Asset retirement obligations		458		307
Pension and other postretirement benefits		261		185
Regulatory liabilities		838		830
Other		159		122
Total Deferred Credits and Other Liabilities		2,828		2,492
Commitments and Contingencies (Note 10)		-		-
Total	$	11,502	$	10,165

See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, (Millions of dollars, except per share amounts)	2008			2007			2006
Operating Revenues:
Electric	$	2,236		$	1,954		$	1,877
Gas-regulated		1,247			1,105			1,257
Gas-nonregulated		1,836			1,562			1,429
Total Operating Revenues		5,319			4,621			4,563
Operating Expenses:
Fuel used in electric generation		864			662			615
Purchased power		36			33			28
Gas purchased for resale		2,547			2,161			2,213
Other operation and maintenance		675			648			619
Depreciation and amortization		319			324			333
Other taxes		168			160			152
Total Operating Expenses		4,609			3,988			3,960

Operating Income		710			633			603

Other Income (Expense):
Other income		79			99			145
Other expenses		(42	)		(48	)		(93	)
Interest charges, net of allowance for borrowed funds used during construction of $16, $13 and $8		(227	)		(206	)		(209	)
Preferred dividends of subsidiary		(7	)		(7	)		(7	)
Allowance for equity funds used during construction		14			2			-
Total Other Expense		(183	)		(160	)		(164	)

Income Before Income Taxes, Earnings (Losses) from Equity Method Investments and Cumulative Effect of Accounting Change		527			473			439
Income Tax Expense		189			140			119

Income Before Earnings (Losses) from Equity Method Investments
and Cumulative Effect of Accounting Change		338			333			320
Earnings (Losses) from Equity Method Investments		8			(13	)		(16	)
Cumulative Effect of Accounting Change, net of taxes		-			-			6

Net Income	$	346		$	320		$	310

Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change	$	2.95		$	2.74		$	2.63
Cumulative Effect of Accounting Change, net of taxes		-			-			.05
Basic and Diluted Earnings Per Share	$	2.95		$	2.74		$	2.68

Weighted Average Common Shares Outstanding (Millions)		117.0			116.7			115.8

See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2008			2007			2006
Cash Flows From Operating Activities:
Net Income	$	346		$	320		$	310
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		-			-			(6	)
Excess losses (earnings) from equity method investments, net of distributions		2			14			23
Depreciation and amortization		327			330			347
Amortization of nuclear fuel		17			19			17
Gain on sale of assets and investments		(10	)		(9	)		(3	)
Allowance for equity funds used during construction		(14	)		(2	)		-
Carrying cost recovery		(5	)		(6	)		(7	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables		(21	)		17			218
Inventories		(114	)		(41	)		(80	)
Prepayments and other		(103	)		(23	)		(2	)
Pension and postretirement benefits		(10	)		(9	)		(16	)
Other regulatory assets		(23	)		40			(32	)
Deferred income taxes, net		76			22			5
Regulatory liabilities		(13	)		94			9
Accounts payable		(14	)		(38	)		(77	)
Taxes accrued		(28	)		35			9
Interest accrued		18			-			(1	)
Changes in fuel adjustment clauses		(91	)		(19	)		3
Changes in other assets		7			13			30
Changes in other liabilities		107			(27	)		6
Net Cash Provided From Operating Activities		454			730			753
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(833	)		(712	)		(485	)
Proceeds from sale of assets and investments		19			10			21
Nonutility property additions		(71	)		(13	)		(42	)
Investments		(2	)		(10	)		(25	)
Net Cash Used For Investing Activities		(887	)		(725	)		(531	)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock		42			6			79
Proceeds from issuance of debt		1,526			40			132
Repayments of debt		(231	)		(34	)		(156	)
Redemption/repurchase of equity securities		-			(14	)		-
Dividends		(219	)		(210	)		(198	)
Short-term borrowings, net		(547	)		140			60
Net Cash Provided From (Used For) Financing Activities		571			(72	)		(83	)
Net Increase (Decrease) in Cash and Cash Equivalents		138			(67	)		139
Cash and Cash Equivalents, January 1		134			201			62
Cash and Cash Equivalents, December 31	$	272		$	134		$	201
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $16, $13 and $8)	$	196		$	172		$	212
-Income taxes		121			76			100
Noncash Investing and Financing Activities:
Accrued construction expenditures		92			82			54

See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME

									Accumulated
									Other
	Common Stock					Retained			Comprehensive
Millions	Shares		Amount			Earnings			Income (Loss)			Total
Balance as of December 31, 2005	115	$	1,332		$	1,349		$	(4	)	$	2,677
Comprehensive Income (Loss):
Net Income						310						310
Other Comprehensive Income (Loss), net of taxes $(8)									(14	)		(14	)
Total Comprehensive Income (Loss)						310			(14	)		296
Deferred Cost of Employee Benefit Plans, net of taxes $(7)									(11	)		(11	)
Issuance of Common Stock upon Exercise of Options	2		79									79
Dividends Declared on Common Stock						(195	)					(195	)
Balance as of December 31, 2006	117		1,411			1,464			(29	)		2,846
Comprehensive Income :
Net Income						320						320
Other Comprehensive Income, net of taxes $3									7			7
Total Comprehensive Income						320			7			327
Issuance of Common Stock Upon Exercise of Options			9			(3	)					6
Repurchase of Common Stock			(13	)								(13	)
Dividends Declared on Common Stock						(206	)					(206	)
Balance as of December 31, 2007	117		1,407		$	1,575			(22	)		2,960
Comprehensive Income (Loss):
Net Income						346						346
Other Comprehensive Loss, net of taxes $(53)									(87	)		(87	)
Total Comprehensive Income (Loss)						346			(87	)		259
Issuance of Common Stock	1		42									42
Dividends Declared on Common Stock						(216	)					(216	)
Balance as of December 31, 2008	118	$	1,449		$	1,705		$	(109	)	$	3,045

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

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

Regulated businesses	Nonregulated businesses
South Carolina Electric & Gas Company (SCE&G)	SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc. (Fuel Company)	SCANA Communications, Inc. (SCI)
South Carolina Generating Company, Inc. (GENCO)	ServiceCare, Inc.
Public Service Company of North Carolina, Incorporated (PSNC Energy)	SCANA Resources, Inc.
Carolina Gas Transmission Corporation (CGTC)	SCANA Services, Inc.
	SCANA Corporate Security Services, Inc.
	Westex Holdings, LLC

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

B. Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of SFAS 71, which requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded the regulatory assets and regulatory liabilities, summarized as follows.

	December 31,
Millions of dollars	2008		2007
Regulatory Assets:
Accumulated deferred income taxes	$	171	$	161
Environmental remediation costs		27		26
Asset retirement obligations and related funding		265		274
Franchise agreements		50		52
Deferred employee benefit plan costs		345		120
Other		47		79
Total Regulatory Assets	$	905	$	712

Regulatory Liabilities:
Accumulated deferred income taxes	$	32	$	35
Other asset removal costs		688		643
Storm damage reserve		48		49
Planned major maintenance		11		15
Monetization of bankruptcy claim		43		45
Other		16		43
Total Regulatory Liabilities	$	838	$	830

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

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Environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G are being recovered through rates, of which $19.4 million remain to be recovered. SCE&G is authorized to amortize $1.4 million of these costs annually. At sites owned by PSNC Energy, costs totaling $3.5 million are being recovered through rates over a three-year period beginning November 2008. In addition, management believes that estimated remaining costs of $4.5 million will be recoverable by PSNC Energy through rates.

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

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

Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities under provisions of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” but which are expected to be recovered through utility rates (see Note 3 and Note 6).

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates. SCE&G applied $7.3 million of costs in 2008 and $1.4 million of costs in 2007 to the reserve. See Note 2.

Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in advance of the time the costs are incurred, as approved through specific SCPSC orders. SCE&G collects $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which will be amortized into operating revenue through the year 2024.

The SCPSC or the North Carolina Utilities Commission (NCUC) (collectively, state commissions) or the United States Federal Energy Regulatory Commission (FERC) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by a state commission or by FERC. 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 of these costs is subject to regulatory approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C. Utility Plant and Major Maintenance

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

SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) jointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G’s portion of Summer Station was $1.0 billion as of December 31, 2008 and 2007 (including amounts related to ARO). Accumulated depreciation associated with SCE&G’s share of Summer Station was $527.6 million and $513.1 million as of December 31, 2008 and 2007, respectively (including amounts related to ARO). SCE&G’s share of the direct expenses associated with operating Summer Station is included in other operation and maintenance expenses and totaled $87.4 million in 2008, $86.7 million in 2007 and $77.5 million in 2006.

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In addition, SCE&G and Santee Cooper are constructing two new nuclear units at the site of Summer Station that will be jointly owned in the proportions of 55 percent and 45 percent, respectively. Each party provides its own financing. SCE&G will be the operator of the new units. SCE&G’s portion of the construction work in progress for the new units was $126.7 million at December 31, 2008 and $22.4 million at December 31, 2007.

Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, SCE&G collects $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2008, SCE&G incurred $7.7 million for turbine maintenance. The remaining balance is in a regulatory liability account on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage upon completion of the preceding outage. SCE&G accrued $1.0 million per month from July 2005 through December 2006 for its portion of the outage in the fall of 2006, accrued $1.1 million per month from January 2007 through June 2008 for its portion of the outage in the spring of 2008, and is accruing $1.2 million per month for its portion of the outage scheduled for the fall of 2009. Total costs for the 2006 outage were $25.8 million, of which SCE&G was responsible for $17.2 million. Total costs for the 2008 outage were $25.7 million, of which SCE&G was responsible for $17.1 million. As of December 31, 2008 and 2007, SCE&G had an accrued balance of $7.3 million and $12.7 million, respectively.

D. Allowance for Funds Used During Construction (AFC)

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 6.3% for 2008, 6.2% for 2007 and 5.5% for 2006. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

E. Revenue Recognition

The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered, but not yet billed. Unbilled revenues totaled $185.1 million at December 31, 2008 and $175.5 million at December 31, 2007.

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

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the state commission during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual hearing. In addition, included in these amounts are realized and unrealized gains and losses incurred in the natural gas hedging programs of the Company’s regulated operations.

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

Prior to November 1, 2008, PSNC Energy’s gas rate schedules for residential, small commercial and small industrial customers included a WNA. Effective November 1, 2008, PSNC Energy was authorized by the NCUC to implement a customer usage tracker (CUT) which allows PSNC Energy to periodically adjust its base rates for residential and commercial customers based on average per customer consumption. Concurrent with implementation of the CUT, the WNA was discontinued.

F. Depreciation and Amortization

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

	2008		2007		2006
SCE&G	3.18	%	3.16	%	3.19	%
GENCO	2.66	%	2.66	%	2.66	%
CGTC	1.92	%	2.00	%	2.04	%
PSNC Energy	3.06	%	3.28	%	3.69	%
Aggregate of Above	3.11	%	3.12	%	3.19	%

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

The Company considers amounts categorized by FERC as “acquisition adjustments” to be goodwill as defined in SFAS 142, “Goodwill and Other Intangible Assets,” and has ceased amortization of such amounts. These amounts are related to acquisition adjustments of $210 million recorded by PSNC Energy (Gas Distribution segment) and $20 million recorded by CGTC (Gas Transmission segment). In accordance with SFAS 142, the Company performs annual impairment evaluations. Should a write-down be required in the future, such a charge would be treated as an operating expense.

G. Nuclear Decommissioning

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

Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2008, 2007 and 2006) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds, and interest on proceeds, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

H. Income and Other Taxes

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

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

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

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

J. Environmental

The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates.

K. Cash and Cash Equivalents

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

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L. Commodity Derivatives

The Company records derivatives contracts at their fair value in accordance with SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and adjusts fair value each reporting period. The Company determines fair value of most of the energy-related derivatives contracts using quotations that reference actively traded contracts. For other derivatives contracts, the Company uses published market surveys and, in certain cases, brokers to obtain quotes concerning fair value. Market quotes tend to be more plentiful for those derivatives contracts maturing in two years or less. See Note 9.

M. New Accounting Matters

SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities,” was issued in March 2008. SFAS 161 requires enhanced disclosures about an entity’s derivative and hedging activities to include how derivative instruments are accounted for and the effect of such activities on the entity’s financial statements. SFAS 161 is effective for fiscal years beginning after November 15, 2008. The Company believes it will likely be required to provide additional disclosures as a part of future financial statements.

SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements,” was issued in December 2007. SFAS 160 requires entities to report noncontrolling (minority) interests in subsidiaries as equity. SFAS 160 is effective for fiscal years beginning after December 15, 2008. Initial adoption of SFAS 160 is not expected to affect the Company’s results of operations, cash flows or financial position.

SFAS 141(R), “Business Combinations,” was issued in December 2007. SFAS 141(R) requires the acquiring entity in a business combination to recognize the assets acquired and the liabilities assumed at their fair values at the acquisition date. SFAS 141(R) also requires the acquirer to disclose all of the information needed to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. Initial adoption of SFAS 141(R) is not expected to affect the Company’s results of operations, cash flows or financial position.

SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 became effective for fiscal years beginning after November 15, 2007. The Company has not elected to measure at fair value any permitted items that are not otherwise required to be measured at fair value. As a result, initial adoption of SFAS 159 did not affect the Company’s results of operations, cash flows or financial position.

The Company adopted SFAS 157, “Fair Value Measurements,” in the first quarter of 2008. SFAS 157 establishes a framework for measuring the fair value of assets and liabilities recognized in the financial statements in periods subsequent to initial recognition. The initial adoption of SFAS 157 did not impact the Company’s results of operations, cash flows or financial position. In addition, Financial Accounting Standards Board (FASB) Staff Position 157-3 (FSP FAS 157-3), “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” issued on October 10, 2008, did not affect the Company’s disclosure of fair value. See Note 9.

FASB Staff Position FAS 132(R), “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)), was issued on December 30, 2008. FSP FAS 132(R) amends SFAS 132(R) to require enhanced disclosures about an employer’s plan assets in a defined benefit pension plan or other postretirement plan. The disclosures required, similar to those required under SFAS 157, include a discussion on the inputs and valuation techniques used to develop fair value measurements of plan assets. In addition, the fair value of each major category of plan assets is required to be disclosed separately for pension plans and other postretirement benefit plans. FSP FAS 132(R) is effective for fiscal years ending after December 15, 2009. Initial adoption of FSP FAS 132(R) is not expected to affect the Company’s results of operations, cash flows or financial position.

N. Earnings Per Share

In accordance with SFAS 128, “Earnings Per Share,” the Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has issued no securities that would have an antidilutive effect on earnings per share.

O. Affiliated Transactions

The Company received cash distributions from equity investees of $6.2 million in 2008, $7.8 million in 2007 and $6.7 million in 2006. The Company made cash investments in equity investees of $2.2 million in 2008, $16.2 million in 2007 and $18.4 million in 2006.

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SCE&G purchases shaft horsepower from a cogeneration facility. The facility is owned by a limited liability company (LLC) in which, prior to July 1, 2008, SCANA held an equity method investment. Transactions subsequent to June 30, 2008 were not affiliated transactions. SCE&G’s payables to the LLC were $2.1 million at December 31, 2007. SCE&G purchased shaft horsepower from the LLC of $14.7 million in 2008, $27.7 million in 2007 and $27.0 million in 2006.

SCE&G held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel. The partnerships ceased operations in 2007 as a result of the expiration of the synthetic fuel tax credit program at the end of 2007, and they were dissolved in 2008. SCE&G’s receivables from these affiliated companies were $28.8 million and payables to these affiliated companies were $26.9 million at December 31, 2007. SCE&G purchased synthetic fuel from these affiliated companies of $281.6 million in 2007 and $291.1 million in 2006.

P. Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

2. RATE AND OTHER REGULATORY MATTERS

SCE&G

Electric

SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. On October 30, 2008, the SCPSC approved a settlement agreement between SCE&G and the South Carolina Office of Regulatory Staff (ORS), whereby SCE&G increased the fuel cost portion of its electric rates. SCE&G sought the increase due to significant increases in fuel costs through the first half of 2008. The increase was effective with the first billing cycle of November 2008.

By Order dated October 7, 2008, the SCPSC approved SCE&G’s request to begin initial clearing, excavation and construction activities related to the proposed nuclear generation project discussed below.

On March 31, 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. On September 26, 2008 the NRC issued a thirty month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC continue to be in progress and should support a COL issuance by July 2011. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.

In a December 2007 order, the SCPSC granted SCE&G an increase in retail electric revenues of approximately $76.9 million, or 4.4%, based on a test year calculation. The order granted an allowed return on common equity of 11%. The new rates became effective January 1, 2008. In that order, the SCPSC also extended through 2015 its approval of the accelerated capital recovery plan for SCE&G’s Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year. No such additional depreciation has been recognized.

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In October 2007, the SCPSC approved SCE&G’s request to increase the storm damage reserve cap from $50 million to $100 million. In addition, the SCPSC approved SCE&G’s request to apply certain transmission and distribution insurance premiums against the reserve until SCE&G files its next retail electric rate case, and in December 2008, the SCPSC approved SCE&G’s request to apply certain tree trimming expenditures in excess of amounts included in base rates during 2008 and 2009.

In May 2007, South Carolina law was changed to revise the statutory definition of fuel costs to include certain variable environmental costs such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The revised definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, and mercury and particulates.

SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. In May 2006, SCE&G agreed to spread the recovery of previously under-collected fuel costs of $38.5 million over a two-year period.

Gas

By Order dated October 14, 2008, the SCPSC approved an increase in SCE&G’s retail gas base rates of $3.7 million, effective the first billing cycle of November 2008. This action was the result of a review by the ORS of SCE&G’s rate of return report for gas distribution operations for the 12-month period ended March 31, 2008, as mandated by the South Carolina Natural Gas Rate Stabilization Act (RSA). The approved rate increase will allow SCE&G the opportunity to earn a 10.25 percent return on common equity as established in its last general retail natural gas base rate case proceeding in 2005. The RSA provides for rate adjustments, either upward or downward, on an annual basis to reflect ongoing changes in investments and in revenues and expenses associated with maintaining and expanding the company’s natural gas service infrastructure.

In October 2007 the SCPSC approved an increase in retail natural gas base rates of 0.9% under the terms of the RSA. The rate adjustment was effective with the first billing cycle in November 2007.

SCE&G’s tariffs include a purchase gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G's rates are calculated using a methodology which adjusts the cost of gas monthly based on a twelve-month rolling average.

PSNC Energy

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

On October 24, 2008, the NCUC granted PSNC Energy an annual increase in natural gas margin revenues of approximately $9.1 million, offset by an $8.4 million reduction in fixed gas costs, for a net annual increase in rates and charges to customers of approximately $0.7 million. PSNC Energy was authorized to implement a CUT. The CUT will allow PSNC Energy to periodically adjust its base rates for residential and commercial customers based on average per customer consumption. The new rates were effective for services rendered on or after November 1, 2008.

In December 2008, in connection with PSNC Energy’s 2008 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-months ended March 31, 2008.

In May 2007 the NCUC approved PSNC Energy’s request to eliminate the use of its dual residential customer rate structure and replace it with a single residential rate. The NCUC also ordered that PSNC Energy establish a new residential rate structure by November 1, 2007. In October 2007 the NCUC approved PSNC Energy’s request to implement a residential service rate which has a winter/summer differential of 6 cents per therm effective November 1, 2007. The higher winter rate will help recover costs associated with operating the system during high customer demand. These changes in the rate structure had no impact on 2007 earnings.

In October 2006, the NCUC granted PSNC Energy an annual increase in retail natural gas margin revenues of approximately $15.2 million, or 2.6%, which was offset by a $9.2 million decrease in fixed-gas cost revenues, for an overall increase of $6 million, or 1.0%. The rates were based on an allowed overall rate of return of 8.9%, and became effective for services rendered on or after November 1, 2006. In connection with the rate increase, the NCUC approved PSNC Energy’s recovery through rates, over a three-year period, of certain costs for environmental remediation and pipeline integrity management.

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3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

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

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

In addition to pension benefits, the Company provides certain unfunded postretirement health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.

Funded Status

	Pension Benefits					Other Postretirement Benefits
December 31,	2008			2007		2008			2007
	Millions of Dollars
Fair value of plan assets	$	629.4		$	929.5		-			-
Benefit obligations		709.5			704.8	$	192.5		$	196.8
Funded status	$	(80.1	)	$	224.7	$	(192.5	)	$	(196.8	)

Amounts recognized on the consolidated balance sheets consist of:

	Pension Benefits					Other Postretirement Benefits
December 31,	2008			2007		2008			2007
		Millions of dollars
Noncurrent asset		-		$	224.7		-			-
Current liability		-			-	$	(11.6	)	$	(11.9	)
Noncurrent liability	$	(80.1	)		-		(180.9	)		(184.9	)

Amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2008 and 2007 were as follows:

		Pension Benefits				Other Postretirement Benefits
December 31,		2008		2007		2008		2007
Net actuarial loss	$	49.6	$	7.5	$	0.7	$	1.4
Prior service cost		0.8		0.9		0.3		0.4
Transition obligation		-		-		0.5		0.6
Total	$	50.4	$	8.4	$	1.5	$	2.4

Changes in Benefit Obligations

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2008			2007			2008			2007
Benefit obligation, January 1	$	704.8		$	713.0		$	196.8		$	206.9
Service cost		15.1			15.3			4.0			4.4
Interest cost		43.2			40.5			12.0			11.7
Plan participants' contributions		-			-			2.7			2.6
Plan amendments		-			7.5			-			-
Actuarial gain		(12.2	)		(25.1	)		(9.2	)		(14.8	)
Benefits paid		(41.4	)		(46.4	)		(13.8	)		(14.0	)
Benefit obligation, December 31	$	709.5		$	704.8		$	192.5		$	196.8

The accumulated benefit obligation for retirement benefits at the end of 2008 and 2007 were $674.6 million and $668.3 million, respectively. These accumulated retirement benefit obligation differ from the projected retirement benefit obligation above in that they reflect no assumptions about future compensation levels.

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

					Other
	Pension				Postretirement
	Benefits				Benefits
	2008		2007		2008			2007
Annual discount rate used to determine benefit obligation	6.45	%	6.25	%		6.45	%		6.30	%
Assumed annual rate of future salary increases for projected benefit obligation	4.00	%	4.00	%		4.00	%		4.00	%

An 8.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2009. The rate was assumed to decrease gradually to 5.0% for 2015 and to remain at that level thereafter.

A one percent point increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at December 31, 2008 and December 31, 2007 by $1.9 million and $2.4 million, respectively. A one percent point decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 2008 and December 31, 2007 by $1.7 million and $2.1 million, respectively.

Changes in Plan Assets

	Pension Benefits
Millions of dollars	2008			2007
Fair value of plan assets, January 1	$	929.5		$	912.5
Actual return on plan assets		(258.7	)		63.4
Benefits paid		(41.4	)		(46.4	)
Fair value of plan assets, December 31	$	629.4		$	929.5

The Company determines the fair value of a majority of its pension assets utilizing market quotes, with the remaining fair value derived from modeling techniques that incorporate market data. At December 31, 2008, both the projected benefit obligation and the accumulated benefit obligation, $709.5 million and $674.6 million, respectively, exceeded the fair value of plan assets of $629.4 million. At December 31, 2007, the fair value of plan assets of $929.5 million exceeded both the projected benefit obligation of $704.8 million and the accumulated benefit obligation of $668.3 million.

In connection with the joint ownership of Summer Station, as of December 31, 2008 and 2007, the Company recorded $12.1 million within deferred debits and $1.3 million within deferred credits, respectively, attributable to Santee Cooper’s one-third portion of shared costs. As of December 31, 2008 and 2007, the Company also recorded within deferred debits a $9.3 million and $9.5 million receivable, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.

Expected Cash Flows

The total benefits expected to be paid from the pension plan or from the Company's assets for the other postretirement benefits plan, respectively, are as follows:

			Other Postretirement Benefits*
Expected Benefit Payments	Pension Benefits		Excluding Medicare Subsidy		Including Medicare Subsidy		.
	Millions of dollars

2009	$	52.7	$	12.2	$	11.9
2010		54.0		12.8		12.4
2011		60.7		13.0		12.7
2012		63.5		13.2		12.9
2013		63.0		13.6		13.3
2014-2018		318.1		74.8		73.3

* Net of participant contributions

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Net Periodic Benefit Cost (Income)

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

Components of Net Periodic Benefit Cost (Income)

	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2008			2007			2006			2008		2007			2006
Service cost	$	15.1		$	15.3		$	14.0		$	4.0	$	4.4		$	4.6
Interest cost		43.2			40.5			39.8			12.0		11.7			11.5
Expected return on assets		(81.1	)		(79.8	)		(75.2	)		n/a		n/a			n/a
Prior service cost amortization		7.0			6.6			6.8			1.0		1.1			1.1
Amortization of actuarial loss		-			-			0.5			-		0.9			1.7
Transition amount amortization		-			-			0.6			0.7		(0.2	)		0.8
Net periodic benefit (income) cost	$	(15.8	)	$	(17.4	)	$	(13.5	)	$	17.7	$	17.9		$	19.7

Other changes in plan assets and benefit obligations recognized in other comprehensive income were as follows:

	Pension Benefits								Other Postretirement Benefits
December 31,	2008			2007			2006		2008			2007			2006
Current year actuarial (gain)/loss	$	42.1		$	0.9		$	n/a	$	(0.7	)	$	(0.9	)	$	n/a
Amortization of actuarial loss		-			-			n/a		-			(0.1	)		n/a
Current year prior service cost		-			0.1			n/a		-			-			n/a
Amortization of prior service cost		(0.1	)		(0.1	)		n/a		(0.1	)		(0.2	)		n/a
Amortization of transition obligation		-			-			n/a		(0.1	)		-			n/a
Total recognized in other comprehensive income	$	42.0		$	0.9		$	n/a	$	(0.9	)	$	(1.2	)	$	n/a

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

	Pension Benefits									Other Postretirement Benefits
	2008			2007			2006			2008		2007			2006
Discount rate		6.25	%		5.85	%		5.60	%	6.30	%		5.85	%		5.60	%
Expected return on plan assets		9.00	%		9.00	%		9.00	%	n/a			n/a			n/a
Rate of compensation increase		4.00	%		4.00	%		4.00	%	4.00	%		4.00	%		4.00	%
Health care cost trend rate		n/a			n/a			n/a		9.00	%		9.50	%		9.00	%
Ultimate health care cost trend rate		n/a			n/a			n/a		5.00	%		5.00	%		5.00	%
Year achieved		n/a			n/a			n/a		2014			2013			2012

The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2009 are as follows:

				Other
		Pension		Postretirement
Millions of Dollars		Benefits		Benefits
Actuarial (gain)/loss	$	5.9	$	-
Prior service (credit)/cost		0.1		0.1
Transition obligation		-		0.1
Total	$	6.0	$	0.2

Other postretirement benefit costs are subject to annual per capita limits pursuant to plan design. As a result, the effect of a one-percentage-point increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $150,000.

Pension Plan Contributions

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

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Pension Plan Asset Allocations

The Company's pension plan asset allocation at December 31, 2008 and 2007 and the target allocation for 2009 are as follows:

	Percentage of Plan Assets
	Target Allocation		At December 31,
Asset Category	2009		2008		2007
Equity Securities		65%		61%		71%
Debt Securities		35%		39%		29%

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

For 2009, the expected long-term rate of return on assets will be 8.5%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan's historical cumulative actual returns over several periods, and assumes an asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.

Share-Based Compensation

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

SFAS 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $.05 per share (net of taxes) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.

Liability Awards

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

Beginning with the 2007-2009 performance cycle, the Plan provides for performance measurement and award determination on an annual basis (rather than the above described three-year measurement and determination), with payment of awards being deferred until after the end of the three-year performance cycle. Accordingly, payouts under the 2007 three-year cycle will be earned for each year that performance goals are met during the three-year cycle, though payments will be deferred until the end of the cycle and will be contingent upon the participant still being employed by the Company at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.

In the 2008-2010 performance cycle, 20% of the performance award was granted in the form of restricted (nonvested) shares, which are equity awards more fully described below. The remaining 80% of the award was made in performance shares. The payment of performance shares for the 2008-2010 performance cycle will be based on SCANA’s performance against pre-determined measures of TSR (weighted 50%) and the growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%).

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Under SFAS 123(R), compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities were paid totaling $2.6 million in 2008 and $6.4 million in 2006. No such payments were made in 2007.

Fair value adjustments for performance awards resulted in an increase to compensation expense recognized in the statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $17.2 million for the year ended December 31, 2008 and $6.6 million for the year ended December 31, 2007, compared to a reduction to compensation expense totaling $(6.5) million for the year ended December 31, 2006. Fair value adjustments resulted in capitalized compensation costs of $1.9 million during the year ended December 31, 2008, and $0.7 million in 2007, compared to a net credit to capitalized compensation costs of $(0.8) million in 2006.

Equity Awards

A summary of activity related to nonvested shares follows:

		Weighted Average
		Grant-Date
Nonvested Shares	Shares	Fair Value
Nonvested at January 1, 2008	-	$	-
Granted	75,824		37.33
Vested	-		-
Forfeited	1,236		37.35
Nonvested at December 31, 2008	74,588		37.33

Nonvested shares are granted at a price corresponding to the opening price of SCANA common stock on the date of the grant. The Company expensed compensation costs for nonvested shares of $0.8 million and recognized related tax benefits of $0.3 million in 2008. The Company capitalized compensation costs of $0.1 million in 2008.

As of December 31, 2008 there was $1.9 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements under the Plan. The cost is expected to be recognized over a weighted-average remaining period of 2.0 years.

A summary of activity related to nonqualified stock options follows:

Stock Options	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2005		439,270		$	27.53
Exercised		(53,330	)		27.52
Outstanding-December 31, 2006		385,940			27.56
Exercised		(258,756	)		27.62
Outstanding-December 31, 2007		127,184			27.45
Exercised		(20,720	)		27.49
Outstanding-December 31, 2008		106,464			27.44

No stock options have been granted since August 2002, and all options were fully vested in August 2005. No options were forfeited during any period presented. The options expire ten years after the grant date. At December 31, 2008, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 2.9 years.

The exercise of stock options during 2006-2008 was satisfied using a combination of original issue shares and open market purchases of the Company’s common stock. The Company realized $0.6 million, $7.1 million and $1.5 million in cash upon the exercise of options in the years ended December 31, 2008, 2007 and 2006, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $0.1 million, $1.5 million and $0.3 million were credited to additional paid in capital (common equity) in these periods. The Company does not expect to repurchase shares during 2009 to satisfy the exercise of stock options.

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4. LONG-TERM DEBT

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

			2008					2007
Dollars in millions	Maturity		Balance		Rate			Balance		Rate
Medium-Term Notes (unsecured)	2011-2020	$	950		6.51	%	$	915		6.35	%
Senior Notes (unsecured) (a)	2034		80		6.47	%		40		6.47	%
First Mortgage Bonds (secured)	2009-2038		2,335		6.07	%		1,675		6.00	%
GENCO Notes (secured)	2011-2024		276		5.95	%		119		5.86	%
Industrial and Pollution Control Bonds (b)	2012-2038		228		4.63	%		156		5.24	%
Senior Debentures(c)	2012-2026		113		7.39	%		116		7.43	%
Borrowings Under Credit Agreements	2011		456		1.67	%		-
Fair value of interest rate swaps (d)			12					17
Other	2009-2027		69					80
Total debt			4,519					3,118
Current maturities of long-term debt			(144	)				(233	)
Unamortized discount			(14	)				(6	)
Total long-term debt, net		$	4,361				$	2,879

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

(b) Includes $71.4 million of variable rate debt hedged by fixed rate swaps in 2008.

(c)	Includes $12.8 million of fixed rate debt hedged by a variable interest rate swap in 2008 compared to $16.0 million of such debt in 2007.

(d)	Represents unamortized payments received to terminate previous swaps designated as fair value hedges. See discussion at Note 9.

The increase in long-term debt in 2008 is primarily the result of financing construction expenditures and securing alternate sources of liquidity during a period of limited access to commercial paper.

The annual amounts of long-term debt maturities for the years 2009 through 2013 are summarized as follows:

Year	Millions of dollars
2009	$	144
2010		25
2011		1,085
2012		275
2013		167

In June 2007 SCANA entered into an agreement to issue and sell Floating Rate Senior Notes due June 1, 2034, in an aggregate principal amount between $90 million and $110 million. In each of December 2008 and 2007, SCANA issued $40 million of the Floating Rate Senior Notes. The remainder of the notes are to be issued in June 2009.

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

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5. LINES OF CREDIT AND SHORT-TERM BORROWINGS

At December 31, 2008 and 2007, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following lines of credit and short-term borrowings outstanding:

		SCANA				SCE&G (c)							PSNC Energy (c)
Millions of dollars		2008		2007				2008			2007		2008		2007
Lines of credit:
Committed long-term (expire December 2011)
Total	$	200		$	200		$	650		$	650		$	250		$	250
Outstanding bank loans		15			-			285			-			156			-
Weighted average interest rate		2.17	%		-			1.61	%		-			1.72	%		-
Outstanding commercial paper (270 or fewer days) (a)		-			-			34			464			46			157
Weighted average interest rate		-			-			5.69	%		5.74	%		6.15	%		5.74	%
Uncommitted (b):
Total	$	78		$	78		$	-		$	-		$	-		$	-
Used		-			7			-			-			-			-
Weighted average interest rate		-			5.10	%		-			-			-			-

(a) The Company’s committed lines of credit serve to back-up the issuance of commercial paper or to provide liquidity support.

Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term

commercial paper or bank loans.

(b) SCANA, SCE&G or a combination may use the line of credit.

and $250 million, respectively.

The South Carolina Jobs-Economic Development Authority (JEDA) issued $35.0 million of Industrial Revenue Bonds in December 2008, the proceeds of which were loaned to SCE&G. The payment of the principal and interest on the bonds is secured by a letter of credit issued by Branch Banking and Trust Company. The bonds mature on December 1, 2038. This initial credit facility will expire on December 10, 2011. Similarly, JEDA issued $36.4 million of Industrial Revenue Bonds in November 2008, the proceeds of which were loaned to GENCO and guaranteed by SCANA. The bonds mature on December 1, 2038. The payment of the principal and interest on these bonds is secured by a letter of credit issued by Bank of America. This initial credit facility will expire on November 14, 2009.

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

6. COMMON EQUITY

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

With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2008, approximately $56 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

Cash dividends on common stock were declared during 2008, 2007 and 2006 at an annual rate per share of $1.84, $1.76 and $1.68, respectively.

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

Millions of Dollars	2008			2007
Net unrealized losses on cash flow hedging activities, net of taxes of $35 and $7	$	(57	)	$	(11	)
Net unrealized deferred costs of employee benefit plans, net of taxes of $32 and $7		(52	)		(11	)
Total	$	(109	)	$	(22	)

The Company recognized losses of $14.3 million and $19.1 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2008 and 2007, respectively. As described in Note 3, the Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other comprehensive income certain gains, losses, prior service costs and credits that have not yet been recognized through net periodic benefit cost, net of tax effects.

7. PREFERRED STOCK

Retirements under sinking fund requirements are at par values. The aggregate of the annual amounts of purchase or sinking fund requirements for preferred stock for the years 2009 through 2013 is $2.2 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2008 SCE&G had shares of preferred stock authorized and available for issuance as follows:

Par Value	Authorized	Available for Issuance
$100	1,000,000	-
$ 50	575,176	300,000
$ 25	2,000,000	2,000,000

Preferred Stock (Not subject to purchase or sinking funds)

For each of the three years ended December 31, 2008, SCE&G had outstanding 1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par Cumulative Preferred Stock (not subject to purchase or sinking funds).

Preferred Stock (Subject to purchase or sinking funds)

Changes in “Total Preferred Stock (Subject to purchase or sinking funds)” during 2008, 2007 and 2006 are summarized as follows:

	Series
	4.50%, 4.60% (A) & 5.125%			4.60% (B) & 6.00%			Total Shares			Millions of Dollars
Redemption Price	$51.00			$50.50
Balance at December 31, 2005		77,043			99,361			176,404		$	8.8
Shares Redeemed-$50 par value		(2,608	)		(6,600	)		(9,208	)		(0.5	)
Balance at December 31, 2006		74,435			92,761			167,196			8.3
Shares Redeemed-$50 par value		(4,600	)		(4,629	)		(9,229	)		(0.4	)
Balance at December 31, 2007		69,835			88,132			157,967			7.9
Shares Redeemed-$50 par value		(4,600	)		(3,400	)		(8,000	)		(0.4	)
Balance at December 31, 2008		65,235			84,732			149,967		$	7.5

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8. INCOME TAXES

Total income tax expense attributable to income (before cumulative effect of accounting change) for 2008, 2007 and 2006 is as follows:

Millions of dollars	2008			2007			2006
Current taxes:
Federal	$	56		$	101		$	94
State		6			13			9
Total current taxes		62			114			103
Deferred taxes, net:
Federal		114			23			12
State		14			4			5
Total deferred taxes		128			27			17
Investment tax credits:
Deferred-state		5			5			5
Amortization of amounts deferred-state		(3	)		(3	)		(3	)
Amortization of amounts deferred-federal		(3	)		(3	)		(3	)
Total investment tax credits		(1	)		(1	)		(1	)
Total income tax expense	$	189		$	140		$	119

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

Millions of dollars	2008			2007			2006
Income	$	346		$	320		$	304
Income tax expense		189			140			119
Preferred stock dividends		7			7			7
Total pre-tax income	$	542		$	467		$	430

Income taxes on above at statutory federal income tax rate	$	190		$	163		$	151
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		15			12			11
Synthetic fuel tax credits		-			(17	)		(34	)
Deductible dividends-Stock Purchase Savings Plan		(7	)		(7	)		(7	)
Non-taxable recovery of Lake Murray back-up dam project carrying costs		(2	)		(2	)		(2	)
Amortization of federal investment tax credits		(3	)		(3	)		(3	)
Domestic production activities deduction		(1	)		(4	)		(1	)
Other differences, net		(3	)		(2	)		4
Total income tax expense (benefit)	$	189		$	140		$	119

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The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $986 million at December 31, 2008 and $935 million at December 31, 2007 are as follows:

Millions of dollars	2008		2007
Deferred tax assets:
Nondeductible reserves	$	95	$	102
Financial instruments		38		13
Unamortized investment tax credits		51		52
Deferred compensation		21		19
Pension plan income		33		-
Unbilled revenue		12		10
Monetization of bankruptcy claim		16		17
Other		58		22
Total deferred tax assets		324		235

Deferred tax liabilities:
Property, plant and equipment		1,067		977
Pension plan income		-		80
Deferred employee benefit plan costs		132		47
Deferred fuel costs		51		2
Other		60		64
Total deferred tax liabilities		1,310		1,170
Net deferred tax liability	$	986	$	935

The Company files a consolidated federal income tax return and the Company and its subsidiaries file various applicable state and local income tax returns. The Internal Revenue Service (IRS) has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2004 are closed for additional assessment. With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2005.

In June 2008, the Company received an unfavorable decision in its litigation of a state tax issue, which denied the Company a refund of state income tax. Although the decision was rendered by the court of last resort, the Company requested and was granted a rehearing of the case by that court in November 2008. It is reasonably possible that the rehearing could result in a favorable decision to be rendered within twelve months. In 2007, the Company removed $15 million of previously recorded tax benefit from its balance sheet related to this item, in connection with the initial adoption of FIN 48, “Accounting for Uncertainty in Income Taxes.” As a result, the unfavorable decision has had no impact on the Company’s results of operations, cash flows or financial position. If the rehearing is decided in favor of the Company, any change to the unrecognized tax benefit will be within a range of $0 to $15 million. The total amount of unrecognized benefits that, if recognized, would affect the effective tax rate is $15 million. However, the impact on any individual year’s effective tax rate would be immaterial, because any tax benefit recorded would be amortized into earnings over a number of years under SFAS 71. No other material changes in the status of the Company’s tax positions have occurred through December 31, 2008.

A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

	Unrecognized
Millions of dollars		Tax Benefit
Balance at January 1, 2008		$	15
Additions based on tax positions related to the current year			-
Additions for tax positions of prior years			-
Reductions for tax positions of prior years			-
Settlements			-
Balance at December 31, 2008		$	15

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2008, 2007 or 2006.

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9. FINANCIAL INSTRUMENTS

As required by SFAS 107, “Disclosure about Fair Value of Financial Instruments,” financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2008 and 2007 were as follows:

	2008				2007
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value

Long-term debt	$	4,505.6	$	4,591.7	$	3,111.7	$	3,166.1
Preferred stock (subject to purchase or sinking funds)		7.5		7.5		7.9		7.0

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

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

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

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

Investments

SCANA and certain of its subsidiaries hold investments, some of which are marketable securities which are subject to SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities,” mark to market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable or which are otherwise non-marketable, such as life insurance policies. Insurance policies are carried at net cash surrender value. The Company also holds investments in several partnerships and joint ventures which are accounted for using the equity method.

Derivatives

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

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

Commodities

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

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

The Company’s nonregulated gas operations recognize, within cost of gas, gains and losses as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. The Company estimates that most of the December 31, 2008 unrealized loss balance of $32.8 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings within the next twelve months as an increase to gas cost if market prices remain stable. As of December 31, 2008, all of the Company's gas commodity cash flow hedges settle by their terms before the end of 2013.

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain of its natural gas storage facilities. At December 31, 2008, such counterparties held 47% of PSNC Energy’s natural gas inventory, with a carrying value of $53.5 million, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees and, in certain instances, a share of profits. No fees are received under supply service agreements. The agreements expire at various times through March 31, 2009.

Interest Rate Swaps

The Company uses interest rate swap agreements to manage interest rate risk on certain debt instruments. At December 31, 2008 the fair value of the Company’s interest rate swap designated as fair value hedge totaled $0.9 million (gain) related to a notional amount of $12.8 million. At December 31, 2008 the fair value of the Company’s interest rate swaps designated as cash flow hedges totaled $80.8 million (loss) related to a notional amount of $331.4 million.

In the fourth quarter of 2007 SCE&G entered into several 30-year forward-starting swaps aggregating $250 million. These swaps were terminated in January 2008 concurrent with the issuance by SCE&G of $250 million of its First Mortgage Bonds. The loss of approximately $14 million on the settlement of these swaps will be amortized over the 30-year life of the bonds.

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

In anticipation of the issuance of debt, the Company may use interest rate lock or similar swap agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. Payments made or received upon termination of such agreements by regulated subsidiaries are recorded in regulatory assets or regulatory liabilities, respectively, and if by the holding company, are recorded in accumulated other comprehensive income. Payments made or received are amortized to interest expense over the term of the underlying debt. As permitted by SFAS 104, “Statement of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions,” payments received or made are classified as a financing activity in the consolidated statement of cash flows.

Fair Value Measurements

The Company values available for sale securities using quoted prices from a national stock exchange, such as the National Association of Securities Dealers Automated Quotations System, where the securities are actively traded. For commodity derivative assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using broker quotes.

At December 31, 2008, fair value measurements, and the level within the fair value hierarchy of SFAS 157 in which the measurements fall, were as follows:

	Fair Value Measurements at December 31, 2008 Using
Millions of dollars	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets - Available for sale securities	$	2		-		-
Assets - Derivative instruments		9	$	26		-
Liabilities - Derivative instruments		2		138		-

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10. COMMITMENTS AND CONTINGENCIES

A. Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.5 billion. Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $13.5 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 rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material adverse impact on the Company’s results of operations, cash flows and financial position.

B. Environmental

SCE&G

The United States Environmental Protection Agency (EPA) issued a final rule in 2005 known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule without vacatur. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements, including the installation of selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction and wet limestone scrubbers at both Wateree and Williams Stations for sulfur dioxide reduction. SCE&G and GENCO have already begun to install this equipment, and expect to incur capital expenditures totaling approximately $559 million through 2010. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this vacated rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In 2005 the EPA issued the Clean Air Mercury Rule (CAMR) which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule. On February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. The Company expects the EPA will issue a new rule on mercury emissions but cannot predict when such a rule will be issued or what requirements it will impose.

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List in April 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that is expected to be completed in 2009. The site has not been remediated nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

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SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and recovers them through rates (see Note 1).

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $9.5 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates. At December 31, 2008, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

PSNC Energy

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of $4.5 million, which reflects its estimated remaining liability at December 31, 2008. PSNC Energy expects to recover through rates any costs, net of insurance recoveries, allocable to PSNC Energy arising from the remediation of these sites.

C. Claims and Litigation

In February 2008, the consumer affairs staff (the staff) of the Georgia Public Service Commission (GPSC) recommended that the GPSC open an investigation into whether SCANA Energy Marketing, Inc. (SCANA Energy) had overcharged certain of its customers. The staff asserted that SCANA Energy confused certain customers, charged certain customers in excess of published prices, and failed to give proper notice of an alleged change in methodology for computing variable rates. While SCANA Energy believed and continues to believe the staff’s assertions were without merit, in June 2008 SCANA Energy entered into a settlement agreement with the GPSC, agreeing to pay $1.25 million in the form of credits on certain customers’ bills and as a contribution to low-income assistance programs. As of December 31, 2008, credits and contributions totaling $1.15 million had been provided to those customers and programs.

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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 a material adverse impact on the Company’s results of operations, cash flows or financial condition.

D. Nuclear Generation

On May 27, 2008, SCE&G and Santee Cooper announced that they had entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station. SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent. Assuming timely receipt of federal and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. SCE&G’s share of the estimated cash outlays (future value) totals $5.3 billion for plant costs and $646 million for related transmission infrastructure costs.

E. 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 2015. Rent expense totaled approximately $13.5 million, $19.0 million and $15.0 million in 2008, 2007 and 2006, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2009	$	18
2010		8
2011		7
2012		6
2013		4
Thereafter		7
Total	$	50

F. Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, nuclear fuel contracts, construction projects and other commitments totaled $2.8 billion, $2.3 billion and $2.4 billion in 2008, 2007 and 2006, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2009	$	2,102
2010		985
2011		849
2012		504
2013		494
Thereafter		2,695
Total	$	7,629

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

In addition, included in purchase commitments are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such commitments without penalty.

G. Guarantees

The Company issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues. The Company is not required to recognize a liability for guarantees issued on behalf of its subsidiaries unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2008, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled $1.1 billion.

H. Asset Retirement Obligations

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

SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation and relates primarily to the Company’s regulated utility operations. As of December 31, 2008, the Company has recorded an ARO of approximately $105 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $353 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

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

Millions of dollars	2008			2007
Beginning balance	$	307		$	292
Liabilities incurred		1			1
Liabilities settled		(2	)		(2	)
Accretion expense		17			17
Revisions in estimated cash flows		135			(1	)
Ending Balance	$	458		$	307

Revisions in estimated cash flows in 2008 primarily related to the expectation of higher costs associated with coal ash disposal than had been assumed in the prior cash flow analysis.

11. SEGMENT OF BUSINESS INFORMATION

The Company's reportable segments are described below. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.

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

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

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

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

The Company's regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations' product differs from the other segments, as does its generation process and method of distribution. The gas segments differ from each other in their regulatory environment, the class of customers each serves and the marketing strategies resulting from those differences. The marketing segments differ from each other in their respective markets and customer type.

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Disclosure of Reportable Segments (Millions of dollars)

2008	Electric Operations		Gas Distribution		Gas Transmission		Retail Gas Marketing		Energy Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	2,236	$	1,237	$	9	$	632	$	1,205	$	36		$	(36	)	$	5,319
Intersegment Revenue		12		1		40		-		279		368			(700	)		-
Operating Income		523		120		16		n/a		n/a		-			51			710
Interest Expense		15		23		5		1		-		-			183			227
Depreciation and Amortization		254		57		6		2		-		17			(17	)		319
Income Tax Expense		3		25		5		20		1		3			132			189
Net Income (Loss)		n/a		n/a		n/a		33		2		(6	)		317			346
Segment Assets		6,602		2,074		296		201		139		995			1,195			11,502
Expenditures for Assets		859		146		11		-		3		72			(187	)		904
Deferred Tax Assets		4		7		18		7		23		2			(38	)		23

2007
Customer Revenue	$	1,954	$	1,096	$	9	$	584	$	978	$	29		$	(29	)	$	4,621
Intersegment Revenue		7		1		40		-		203		340			(591	)		-
Operating Income		464		111		18		n/a		n/a		-			40			633
Interest Expense		16		26		6		1		-		-			157			206
Depreciation and Amortization		258		56		7		3		-		17			(17	)		324
Income Tax Expense		3		20		8		16		2		5			86			140
Net Income (Loss)		n/a		n/a		n/a		28		3		(18	)		307			320
Segment Assets		5,925		1,956		356		188		123		1,112			505			10,165
Expenditures for Assets		540		154		10		-		2		9			10			725
Deferred Tax Assets		4		8		19		6		6		1			(35	)		9

2006
Customer Revenue	$	1,877	$	1,078	$	179	$	608	$	821	$	66		$	(66	)	$	4,563
Intersegment Revenue		9		-		322		-		128		306			(765	)		-
Operating Income		456		83		30		n/a		n/a		n/a			34			603
Interest Expense		15		24		7		2		-		-			161			209
Depreciation and Amortization		268		54		8		3		-		15			(15	)		333
Income Tax Expense		3		16		11		19		-		6			64			119
Net Income (Loss)		n/a		n/a		n/a		30		-		(11	)		291			310
Segment Assets		5,520		1,847		315		208		142		649			1,136			9,817
Expenditures for Assets		304		174		13		-		3		35			(2	)		527
Deferred Tax Assets		n/a		n/a		7		3		12		2			10			34

Revenues and assets from segments below the quantitative thresholds are attributable to other direct and indirect wholly owned subsidiaries of the Company. These subsidiaries conduct nonregulated operations in energy-related and telecommunications industries. None of these subsidiaries met the quantitative thresholds for determining reportable segments during any period reported.

Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, SCE&G does not allocate interest charges, income tax expense or assets other than utility plant to its segments. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. In accordance with SFAS 109, the Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

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

Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.

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

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12. QUARTERLY FINANCIAL DATA (UNAUDITED)

2008 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,533	$	1,218	$	1,266	$	1,302	$	5,319
Operating income		213		131		189		177		710
Net income		109		57		94		86		346
Basic and diluted earnings per share		.94		.48		.80		.73		2.95

2007 Millions of dollars, except per share amounts
Total operating revenues	$	1,363	$	1,007	$	1,079	$	1,172	$	4,621
Operating income		163		116		189		165		633
Net income		86		55		92		87		320
Basic and diluted earnings per share		.73		.47		.79		.75		2.74

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

			Page

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		82
		Overview	82
		Results of Operations	83
		Liquidity and Capital Resources	87
		Environmental Matters	91
		Regulatory Matters	93
		Critical Accounting Policies and Estimates	93
		Other Matters	95

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		93

Item 8.	Financial Statements and Supplementary Data		98
		Report of Independent Registered Public Accounting Firm	98
		Consolidated Balance Sheets	99
		Consolidated Statements of Income	101
		Consolidated Statements of Cash Flows	102
		Consolidated Statements of Changes in Common Equity	103
		Notes to Consolidated Financial Statements	104

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

OF OPERATIONS

OVERVIEW

South Carolina Electric & Gas Company (SCE&G, together with its consolidated affiliates, the Company) 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 business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 16,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers more than 23,000 square miles.

Key Earnings Drivers and Outlook

The southeast has suffered under the effects of a recession that has progressively worsened during 2008. At December 31, 2008 preliminary estimates of unemployment for South Carolina were 9.5%. While customer growth remained positive throughout 2008, the rate of growth slowed considerably. In addition, SCE&G began to experience declines in customer usage, especially in the fourth quarter of 2008. The Company expects the recession to continue well into 2009, if not longer, and cannot determine when or if customer growth and usage trends may return to pre-2008 levels.

Over the next five years, key earnings drivers for SCE&G will be additions to utility rate base, consisting primarily of capital expenditures for environmental facilities, new generating capacity and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and the level of growth of operation and maintenance expenses.

Electric Operations

The electric operations segment is comprised of the electric operations of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation, transmission and distribution of electricity in South Carolina. At December 31, 2008 SCE&G provided electricity to 649,600 customers in an area covering nearly 16,000 square miles. GENCO owns a coal-fired generation station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowance requirements. Both GENCO and Fuel Company are consolidated with SCE&G for financial reporting purposes.

Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. In January 2005, as a result of an electric rate case, SCE&G’s allowed return on equity may not exceed 11.0%. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

In 2008, SCE&G contracted with Westinghouse Electric Company LLC and Stone & Webster, Inc. for the design and construction of two 1,117-megawatt nuclear electric generating units at the site of V. C. Summer Nuclear Station (Summer Station). SCE&G and South Carolina Public Service Authority (Santee Cooper) will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent. Assuming timely receipt of federal and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. The successful completion of the project would result in an increase of the Company’s utility plant in service of approximately 70% over its 2008 level. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.

Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and is primarily engaged in the purchase and sale of natural gas to retail customers in portions of South Carolina. At December 31, 2008 this segment provided natural gas to approximately 307,200 customers.

Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact SCE&G’s ability to retain large commercial and industrial customers. Significant supply disruptions did occur in September and October 2005 as a result of hurricane activity in the Gulf of Mexico, resulting in the curtailment during the period of most large commercial and industrial customers with interruptible supply agreements. While supply disruptions were not experienced in 2008 or in 2007, the price of natural gas remains volatile and has resulted in short-term competitive pressure. The long-term impact of volatile gas prices and gas supply has not been determined.

RESULTS OF OPERATIONS

Net Income

Net income was as follows:

Millions of dollars	2008		% Change			2007		% Change			2006

Net income	$	273.0		11.4	%	$	245.1		4.5	%	$	234.6

•

2008 vs 2007

Net income increased primarily due to higher electric margin of $49.0 million and higher gas margin of $4.1 million. These increases were partially offset by increased generation, transmission and distribution expenses of $1.6 million, by increased incentive compensation and other benefits of $4.5 million, by increased depreciation expense of $6.9 million, by $2.5 million due to higher customer service expense, including bad debt expense and by $1.2 million due to lower pension income.

•

2007 vs 2006

Net income increased primarily due to higher electric margin of $14.0 million and higher gas margin of $14.4 million. These increases were partially offset by increased generation, transmission and distribution expenses of $2.8 million, by increased incentive compensation and other benefits of $8.8 million and by increased depreciation expense of $7.0 million.

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Pension Income

Pension income was recorded on SCE&G’s financial statements as follows:

Millions of dollars	2008		2007		2006
Income Statement Impact:
Reduction in employee benefit costs	$	2.4	$	4.3	$	2.4
Other income		14.9		14.0		12.7
Balance Sheet Impact:
Reduction in capital expenditures		0.7		1.3		0.7
Component of amount due to Summer Station co-owner		0.3		0.4		0.2
Total Pension Income	$	18.3	$	20.0	$	16.0

The Company expects to record significant amounts of pension expense in 2009 compared to the pension income recorded in 2008. This unfavorable change is expected due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets. However, the Company does not expect that a contribution to the pension trust will be necessary in or for 2009, nor does the Company expect limitations on benefit payments to apply. Additionally, in February 2009, the Company was granted accounting orders by the SCPSC which will allow it to mitigate a significant portion of this increased pension expense by deferring as a regulatory asset the amount of pension expense above that which is included in current rates. These costs will be deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively. See further information at Liquidity and Capital Resources and Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 6.3% of income before income taxes in 2008, 3.8% in 2007 and 2.2% in 2006.

Dividends Declared

SCE&G’s Board of Directors has declared the following dividends on common stock held by SCANA during 2008:

Declaration Date	Dividend Amount		Quarter Ended	Payment Date
February 14, 2008	$	40.7 million	March 31, 2008	April 1, 2008
April 24, 2008		40.8 million	June 30, 2008	July 1, 2008
July 31, 2008		41.3 million	September 30, 2008	October 1, 2008
October 29, 2008		42.2 million	December 31, 2008	January 1, 2009

Electric Operations

Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margins were as follows:

Millions of dollars	2008		% Change			2007		% Change			2006
Operating revenues	$	2,248.1		14.6	%	$	1,961.7		4.0	%	$	1,886.6
Less: Fuel used in generation		865.9		30.7	%		662.3		7.7	%		615.1
Purchased power		36.1		10.4	%		32.7		18.9	%		27.5
Margin	$	1,346.1		6.3	%	$	1,266.7		1.8	%	$	1,244.0

•

2008 vs 2007

Margin increased by $74.5 million due to increased retail electric rates that went into effect in January 2008 and $16.6 million due to residential and commercial customer growth. These increases were offset by $5.4 million due to lower off-system sales, by $3.5 million due to lower industrial sales and $10.0 million in lower residential and commercial usage.

•

2007 vs 2006

Margin increased by $27.3 million due to customer growth and usage and other electric revenue of $5.2 million. These increases were offset by lower off-system sales of $10.2 million.

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

Classification (in thousands)	2008		% Change			2007		% Change			2006
Residential		7,828		0.2	%		7,814		2.8	%		7,598
Commercial		7,453		(0.3	)%		7,472		2.8	%		7,268
Industrial		6,152		(1.8	)%		6,267		1.4	%		6,183
Sales for resale (excluding interchange)		1,850		(11.9	)%		2,100		1.2	%		2,076
Other		569		1.1	%		563		6.8	%		527
Total territorial		23,852		(1.5	)%		24,216		2.4	%		23,652
Negotiated Market Sales Tariff (NMST)		435		(35.3	)%		672		(24.2	)%		886
Total		24,287		(2.4	)%		24,888		1.4	%		24,538

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2008 vs 2007

•

2007 vs 2006

Territorial sales volumes increased by 343 MWh primarily due to residential and commercial customer growth and by 83 MWh due to higher industrial sales volumes.

Gas Distribution

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

Millions of dollars	2008		% Change			2007		% Change			2006
Operating revenues	$	567.8		9.4	%	$	519.1		2.9	%	$	504.6
Less: Gas purchased for resale		428.7		10.9	%		386.7		(2.2	)%		395.5
Margin	$	139.1		5.1	%	$	132.4		21.4	%	$	109.1

•

2008 vs 2007

Margin increased by $3.6 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2007, by $1.1 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2008, and by $2.4 million due to other customer growth.

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2007 vs 2006

Margin increased by $13.6 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2006, and by $1.0 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2007, and by $6.1 million due to other customer growth.

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

Classification (in thousands)	2008		% Change		2007	% Change		2006
Residential	$	12,030	9.2	%	11,014	0.8	%	10,926
Commercial		13,301	8.4	%	12,270	2.4	%	11,984
Industrial		16,615	(8.3	)%	18,126	1.4	%	17,879
Transportation gas		6,403	*		2,811	13.2	%	2,484
Total	$	48,349	9.3	%	44,221	2.2	%	43,273

*Greater than 100%.

•

2008 vs 2007

•

2007 vs 2006

Residential, commercial and transportation gas sales volumes increased primarily due to customer growth.

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Other Operating Expenses

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

Millions of dollars	2008		% Change			2007		% Change			2006
Other operation and maintenance	$	506.2		5.9	%	$	477.9		3.7	%	$	460.7
Depreciation and amortization		265.2		(4.1	)%		276.4		(3.3	)%		285.8
Other taxes		154.2		5.0	%		146.9		6.6	%		137.8
Total	$	925.6		2.7	%	$	901.2		1.9	%	$	884.3

•

2008 vs 2007

Other operation and maintenance expenses increased by $2.6 million due to higher generation, transmission and distribution expenses, by $7.3 million due to higher incentive compensation and other benefits, by $4.1 million due to higher customer service expense, including bad debt expense and by $1.9 million due to lower pension income. Depreciation and amortization expense decreased by $4.6 million due to the 2007 expiration of the synthetic fuel tax credit program (see Income Taxes - Recognition of Synthetic Fuel Tax Credits) and $8.5 million due to the 2007 expiration of a three-year amortization of previously deferred purchase power costs. These decreases were offset by $10.3 million due to 2008 net property additions. Other taxes increased primarily due to higher property taxes.

•

2007 vs 2006

Other operation and maintenance expenses increased by $4.6 million due to higher generation, transmission and distribution expenses and by $14.2 million due to higher incentive compensation and other benefits. Depreciation and amortization expense decreased by $19.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2007 compared to 2006 (see Income Taxes- Recognition of Synthetic Fuel Tax Credits), partially offset by $11.4 million due to 2007 net property additions. Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

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

Millions of dollars	2008			% Change			2007			% Change			2006
Other revenues	$	36.0			8.1	%	$	33.3			(47.8	)%	$	63.8
Other expenses		(16.0	)		44.1	%		(11.1	)		(75.4	)%		(45.1	)
Total	$	20.0			(9.9	)%	$	22.2			18.7	%	$	18.7

•

2008 vs 2007

Other revenues increased by $1.9 million due to increased coal sales to non-affiliates. Other expenses increased $1.7 million due to increased coal inventory expenses related to the increased coal sales to non-affiliates.

•

2007 vs 2006

Other revenues decreased by $32.0 million due to lower levels of power marketing activities. Other expenses decreased $31.2 million due to lower levels of power marketing activities in 2007 and by $8.7 million related to a FERC power marketing settlement in 2006.

Interest Expense

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

Millions of dollars	2008		% Change			2007		% Change			2006
Interest on long-term debt, net	$	138.0		25.9	%	$	109.6		(11.5	)%	$	123.9
Other interest expense		17.2		(44.9	)%		31.2		93.8	%		16.1
Total	$	155.2		10.2	%	$	140.8		0.6	%	$	140.0

•

2008 vs 2007

Interest on long-term debt increased primarily due to increased long-term borrowings in 2008 compared to 2007. Other interest expense decreased primarily due to lower principal balances on short-term debt.

•

2007 vs 2006

Interest on long-term debt decreased primarily due to lower interest rates in 2007 compared to 2006. Other interest expense increased primarily due to higher principal balances and interest rates on short-term debt.

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Income Taxes

Income tax expense increased primarily due to the recognition of $17.4 million in synthetic fuel tax credits in 2007 and due to other changes in operating income. The recognition of these tax credits in 2006 was $33.5 million.

Recognition of Synthetic Fuel Tax Credits

Millions of dollars		2007		2006
Depreciation and amortization expense	$	(8.4	)	$	(28.2	)
Income tax benefits		26.9			48.6
Losses from Equity Method Investments		(18.5	)		(20.4	)
Impact on Net Income	$	-		$	-

Available credits were not sufficient to fully recover the construction costs of dam remediation; therefore, regulatory action to allow recovery of remaining costs will be sought. In addition, SCE&G records non-cash carrying costs on the unrecovered investment, which amounts were $5.5 million in 2008, $5.6 million in 2007 and $6.6 million in 2006. As of December 31, 2008, remaining unrecovered costs were $70.0 million. The Company expects these costs to be recoverable through rates.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company’s ratios of earnings to fixed charges for the 12 months ended December 31, 2008 was 3.51. The Company’s ratio of earnings to combined fixed charges and preference dividends for the same period was 3.29.

The Company’s cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of the Company to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. The Company’s future financial position and results of operations will be affected by SCE&G’s ability to obtain adequate and timely rate and other regulatory relief.

Challenging conditions during 2008 tested the Company’s liquidity and its ability to access short-term funding sources. During this period, all of the banks in the Company’s revolving credit facilities fully funded draws requested of them. As of December 31, 2008, the Company had drawn approximately $285 million from its $650 million facilities, had approximately $34 million in commercial paper borrowings outstanding and approximately $119 million in cash and temporary investments. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.

At December 31, 2008, the Company had net available liquidity of approximately $336 million, and the Company’s revolving credit facilities are in place until December 2011. The Company’s overall debt portfolio has weighted average maturity of over fifteen years and bears an average cost of 5.49%. All long-term debt, other than facility draws, bears fixed interest rates. To further preserve liquidity, the Company rigorously reviewed its projected capital expenditures and operating costs for 2009 and adjusted them where possible without impacting safety, reliability, and core customer service.

The Company's issuance of various securities, including short- and long-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including the SCPSC and Federal Energy Regulatory Commission (FERC).

The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2009-2011, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars	2009		2010		2011
Electric Plant:
Generation (including GENCO)	$	652	$	758	$	897
Transmission		48		46		68
Distribution		178		184		190
Other		40		22		21
Nuclear Fuel		43		78		59
Gas		53		60		59
Common and Other		39		16		17
Total	$	1,053	$	1,164	$	1,311

The Company’s contractual cash obligations as of December 31, 2008 are summarized as follows:

Contractual Cash Obligations

	Payments due by period
Millions of dollars	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long-term and short-term debt (including
interest and preferred stock redemptions)	$	6,160	$	344	$	949	$	480	$	4,387
Capital leases		3		2		1		-		-
Operating leases		34		15		16		3		-
Purchase obligations		349		333		16		-		-
Other commercial commitments		1,545		688		796		25		36
Total	$	8,091	$	1,382	$	1,778	$	508	$	4,423

Not included in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station. SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent. Assuming timely receipt of federal and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. SCE&G’s share of the estimated cash outlays, including contractual amounts not reflected above, are as follows:

Future Value
Millions of dollars	2009		2010		2011		2012		2013		After 2013		Total
Plant Costs	$	472	$	648	$	766	$	734	$	752	$	1,929	$	5,301
Transmission Costs		1		2		5		2		16		620		646

Included in other commercial commitments are estimated obligations for coal and nuclear fuel purchases. See Note 10F to the consolidated financial statements.

Included in purchase obligations are customary purchase orders under which SCE&G has the option to utilize certain vendors without the obligation to do so. SCE&G may terminate such arrangements without penalty.

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

In addition to the contractual cash obligations above, SCANA sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no required contributions are anticipated until after 2010. The Company’s cash payments under the health care and life insurance benefit plan were $8.5 million in 2008, and such annual payments are expected to increase to the $9-$10 million range in the future.

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

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $747 million in 2008 and are estimated to be $1.1 billion in 2009.

Financing Limits and Related Matters

The Company’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including the SCPSC and FERC. Financing programs currently utilized by the Company are as follows.

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of short-term indebtedness. The authority to make such issuances will expire on February 6, 2010.

At December 31, 2008, SCE&G (including Fuel Company) had available the lines of credit and outstanding borrowings under or supported by such lines of credit, as follows:

	Millions of dollars
Lines of credit:
Committed long-term (expire December 2011)
Total	$	650
Outstanding bank loans		285
Weighted average interest rate		1.61	%
Outstanding commercial paper (270 or fewer days) (a)	$	34
Weighted average interest rate		5.69	%
Uncommitted (b):
Total	$	78
Used		-
Weighted average interest rate		-

(a) The Company’s committed lines of credit serve to backup the issuance of commercial paper.

(b) SCE&G, SCANA or a combination may use the line of credit.

The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wachovia Bank, National Association and Bank of America, N. A. each provide 14.3% of the aggregate $650 million credit facilities, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%. Four other banks provide the remaining 9.6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company). When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

Financing Activities

During 2008 the Company experienced net cash inflows related to financing activities of $407 million primarily due to the issuance of long-term debt, partially offset by repayment of short-term debt and payment of dividends.

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In the fourth quarter of 2008, SCE&G entered into a forward starting swap agreement in anticipation of the issuance of First Mortgage Bonds with a tenure of 30 years. At December 31, 2008, the estimated fair value of the Company’s forward starting swap totaled $43.7 million (loss) related to notional amounts of $150 million.

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

ENVIRONMENTAL MATTERS

For the three years ended December 31, 2008, the Company’s capital expenditures for environmental control totaled $526.4 million. These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $43.7 million during 2008, $34.0 million during 2007, and $28.1 million during 2006. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $110.0 million for 2009 and $137.1 million for the four-year period 2010-2013. These expenditures are included in the Company’s Estimated Capital Expenditures table, discussed in Liquidity and Capital Resources, and include the matters discussed below.

At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2008. The Company cannot predict whether such legislation will be introduced or enacted in South Carolina in 2009, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.

Air Quality

The United States Environmental Protection Agency (EPA) issued a final rule in 2005 known as CAIR. CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule without vacatur. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements, including the installation of selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction and wet limestone scrubbers at both Wateree and Williams Stations for sulfur dioxide reduction. SCE&G and GENCO have already begun to install this equipment, and expect to incur capital expenditures totaling approximately $559 million through 2010. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this vacated rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In 2005 the EPA issued the Clean Air Mercury Rule (CAMR) which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule, and on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. The Company expects the EPA will issue a new rule on mercury emissions but cannot predict when such a rule will be issued or what requirements it will impose.

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The current state of continued DOJ enforcement actions is the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $32,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any enforcement actions relative to the Company’s compliance with the CAA would be without merit.. The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the concerns with NSR.

Water Quality

Hazardous and Solid Wastes

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2008, the federal government has not accepted any spent fuel from Summer Station or any other utility, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available.

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

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Electric Operations

Gas Distribution

REGULATORY MATTERS

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

SCE&G is subject to the jurisdiction of the SEC and FERC as to the issuance of certain securities, acquisitions and other matters.

The Company 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Utility Regulation

The Company is subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations or financial position 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 would be materially affected. See Note 1B to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2008 and 2007, accounts receivable included unbilled revenues of $97.1 million and $92.8 million, respectively, compared to total revenues of $2.8 billion and $2.5 billion for the years 2008 and 2007, respectively.

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 the Company’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and timing of cash flows. Changes in any of these estimates could significantly impact the Company’s financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).

Accounting for Pensions and Other Postretirement Benefits

SCANA follows SFAS 87, “Employers’ Accounting for Pensions,” as amended by SFAS 158, “Employees’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” in accounting for the cost of its defined benefit pension plan. SCANA’s plan is adequately funded under current regulations and as such, net pension income is reflected in the financial statements (see Results of Operations-Pension Income). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Aggregate net pension income of $15.8 million ($18.3 million attributable to SCE&G) recorded in 2008 reflects the use of a 6.25% discount rate, derived using a cash flow matching technique, and an assumed 9.00% long-term rate of return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 6.00% in 2008 would have increased SCANA’s aggregate pension income by $0.1 million. Had the assumed long-term rate of return on assets been 8.75%, SCANA’s aggregate pension income for 2008 would have been reduced by $2.3 million.

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As noted in Results of Operations, due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, SCANA expects to record significant amounts of pension expense in 2009 compared to the pension income recorded in 2008 and previously. However, in February 2009, SCANA was granted accounting orders by the SCPSC which will allow it to mitigate a significant portion of this increased pension expense by deferring as a regulatory asset the amount of pension expense above that which is included in current rates for both of SCANA’s South Carolina regulated businesses. These costs will be deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.

Similar to its pension accounting, SCANA follows SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS 158, in accounting for the cost of its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 6.30%, derived using a cash flow matching technique, and recorded a net SFAS 106 cost of $13.0 million for 2008. Had the selected discount rate been 6.05%, the expense for 2008 would have been $0.2 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded

Asset Retirement Obligations

SFAS 143, “Accounting for Asset Retirement Obligations,” together with FIN 47, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates to the Company’s regulated utility operations, SFAS 143 and FIN 47 have no impact on results of operations. As of December 31, 2008, the Company has recorded an ARO of approximately $105 million for nuclear plant decommissioning (as discussed above) and an ARO of $332 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Transactions

SCE&G does not hold investments in unconsolidated special purpose entities such as those described in SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” or as described in FIN 46(R), “Consolidation of Variable Interest Entities.” SCE&G does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, equipment and rail cars.

Claims and Litigation

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

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

All financial instruments held by SCE&G described below are held for purposes other than trading.

The tables below provide information about long-term debt issued by SCE&G which is sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. Fair values for debt represent quoted market prices.

	Expected Maturity Date
December 31, 2008 Millions of dollars	2009		2010	2011	2012	2013	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	103.7		10.4	449.9	11.0	156.7	2,320.2	3,051.9	3,175.8
Average Interest Rate (%)	6.18		6.31	3.48	4.98	7.06	5.89	5.60
Variable Rate ($)		26.1					71.4	97.5	97.5
Average Variable Interest Rate (%)		6.36					3.28	4.10
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)							71.4	71.4	(4.5)
Average Pay Interest Rate (%)							3.28	3.28
Average Receive Interest Rate (%)							1.43	1.43

	Expected Maturity Date
December 31, 2007 Millions of dollars	2008	2009	2010	2011	2012	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	3.7	103.7	10.4	164.9	11.0	1,656.9	1,950.6	1,958.4
Average Interest Rate (%)	7.78	6.18	6.31	6.70	4.98	5.83	5.93

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

The above tables exclude long-term debt of $37 million at December 31, 2008 and $72 million at December 31, 2007, which amounts do not have stated interest rates associated with them.

Commodity Price Risk

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

Expected Maturity:
				Options
	Futures Contracts			Purchased Call	Purchased Put
2009	Long	Short		(Long)	(Long)
Settlement Price (a)	5.76	13.14	Strike Price (a)	12.43	8.39
Contract Amount (b)	14.3	2.8	Contract Amount (b)	14.8	20.8
Fair Value (b)	9.4	6.6	Fair Value (b)	0.1	(6.8)

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

Swaps	2009	2010
Commodity Swaps:
Pay fixed/receive variable (b)	40.8	0.7
Average pay rate (a)	9.2783	11.5542
Average received rate (a)	5.9019	7.3957
Fair Value (b)	26.0	0.5

Pay variable/receive fixed (b)	2.8	-
Average pay rate (a)	5.6248	-
Average received rate (a)	13.0918	-
Fair Value (b)	6.6	-

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

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 9 to the consolidated financial statements.

The New York Mercantile Exchange (NYMEX) futures information above includes the financial positions of SCE&G. SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is deferred.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

South Carolina Electric & Gas Company:

We have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, changes in common equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. 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 South Carolina Electric & Gas Company and affiliates at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/Deloitte & Touche LLP

Columbia, South Carolina

February 27, 2009

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2008			2007
Assets
Utility Plant In Service:	$	8,918		$	8,380
Accumulated Depreciation and Amortization		(2,794	)		(2,643	)
Construction Work in Progress		704			383
Nuclear Fuel, Net of Accumulated Amortization		77			82
Utility Plant, Net		6,905			6,202
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		46			38
Assets held in trust, net-nuclear decommissioning		54			62
Nonutility Property and Investments, Net		100			100
Current Assets:
Cash and cash equivalents		119			41
Receivables, net of allowance for uncollectible accounts of $3 and $2		483			320
Receivables-affiliated companies		23			29
Inventories (at average cost):
Fuel		172			139
Materials and supplies		100			97
Emission allowances		15			33
Prepayments and other		155			52
Deferred income taxes		-			5
Total Current Assets		1,067			716
Deferred Debits and Other Assets:
Due from parent – pension asset, net		-			228
Regulatory assets		854			629
Other		126			102
Total Deferred Debits and Other Assets		980			959
Total	$	9,052		$	7,977

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December 31, (Millions of dollars)	2008		2007
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,704	$	2,622
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,810		2,728
Preferred Stock, net (Subject to purchase or sinking funds)		7		7
Long-Term Debt, net		3,033		2,003
Total Capitalization		5,850		4,738

Minority Interest		95		89

Current Liabilities:
Short-term borrowings		34		464
Current portion of long-term debt		140		13
Accounts payable		187		175
Affiliated payables		80		178
Customer deposits and customer prepayments		56		42
Taxes accrued		120		116
Interest accrued		50		33
Dividends declared		44		37
Derivative liabilities		55		13
Other		28		33
Total Current Liabilities		794		1,104
Deferred Credits and Other Liabilities:
Deferred income taxes, net		890		820
Deferred investment tax credits		102		103
Asset retirement obligations		437		294
Due to parent – pension and other postretirement benefits		236		187
Regulatory liabilities		608		609
Other		40		33
Total Deferred Credits and Other Liabilities		2,313		2,046
Commitments and Contingencies (Note 10)		-		-
Total	$	9,052	$	7,977

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, (Millions of dollars)	2008			2007			2006
Operating Revenues:
Electric	$	2,248		$	1,962		$	1,886
Gas		568			519			505
Total Operating Revenues		2,816			2,481			2,391
Operating Expenses:
Fuel used in electric generation		866			662			615
Purchased power		36			33			27
Gas purchased for resale		429			387			396
Other operation and maintenance		506			478			461
Depreciation and amortization		265			276			286
Other taxes		155			147			138
Total Operating Expenses		2,257			1,983			1,923
Operating Income		559			498			468
Other Income (Expense):
Other income		36			33			64
Other expenses		(16	)		(11	)		(45	)
Interest charges, net of allowance for borrowed funds used during construction of $15, $13 and $8		(155	)		(141	)		(140	)
Allowance for equity funds used during construction		13			2			-
Total Other Expense		(122	)		(117	)		(121	)

Income Before Income Taxes, Earnings (Losses) from Equity Method Investments, Minority
Interest, Cumulative Effect of Accounting Change and Preferred Stock Dividends		437			381			347
Income Tax Expense		158			109			88

Income Before Earnings (Losses) from Equity Method Investments, Minority Interest,
Cumulative Effect of Accounting Change and Preferred Stock Dividends		279			272			259
Earnings (Losses) from Equity Method Investments		3			(20	)		(22	)
Minority Interest		9			7			7
Cumulative Effect of Accounting Change, net of taxes		-			-			4
Net Income		273			245			234
Preferred Stock Cash Dividends		7			7			7
Earnings Available for Common Shareholder	$	266		$	238		$	227

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2008			2007			2006
Cash Flows From Operating Activities:
Net income	$	273		$	245		$	234
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		-			-			(4	)
Losses (earnings) from equity method investments		(3	)		20			22
Minority interest		9			7			7
Depreciation and amortization		265			276			286
Amortization of nuclear fuel		17			19			17
Gain on sale of assets		(8	)		(4	)		(3)
Allowance for equity funds used during construction		(13	)		(2	)		-
Carrying cost recovery		(5	)		(6	)		(7	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables		(9	)		(51	)		49
Inventories		(76	)		(43	)		(146	)
Prepayments		(23	)		(32	)		(8)
Due to/from parent - pension and other postretirement benefits		(21	)		(19	)		(16	)
Regulatory assets		(25	)		17			(10	)
Deferred income taxes, net		99			27			14
Other regulatory liabilities		(7	)		53			9
Accounts payable		13			38			(16	)
Taxes accrued		4			4			(28	)
Interest accrued		17			-			(2	)
Changes in fuel adjustment clauses		(133	)		5			32
Changes in other assets		12			45			19
Changes in other liabilities		44			(59	)		25
Net Cash Provided From Operating Activities		430			540			474
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(739	)		(613	)		(409	)
Nonutility property additions		(8	)		(6	)		(3	)
Proceeds from sales of assets		8			5			3
Investment in affiliate		(18	)		-			-
Investments		(2	)		19			(22	)
Net Cash Used For Investing Activities		(759	)		(595	)		(431	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		1,109			-			132
Contribution from parent		15			76			9
Repayment of debt		(13	)		(6	)		(151	)
Redemption of preferred stock		-			(1	)		-
Dividends		(164	)		(143	)		(162	)
Short-term borrowings - affiliate, net		(110	)		44			75
Short-term borrowings, net		(430	)		102			59
Net Cash Provided From (Used For) Financing Activities		407			72			(38	)
Net Increase (Decrease) in Cash and Cash Equivalents		78			17			5
Cash and Cash Equivalents, January 1		41			24			19
Cash and Cash Equivalents, December 31	$	119		$	41		$	24
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $15, $13 and $8)	$	119		$	104		$	122
- Income taxes		51			70			93
Noncash Investing and Financing Activities:
Accrued construction expenditures		74			58			43

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY

										Accumulated
					Other					Other			Total
	Common Stock (a)				Paid In		Retained			Comprehensive			Common
Millions	Shares		Amount		Capital		Earnings			Income (Loss)			Equity
Balance at December 31, 2005		40	$	571	$	769	$	1,022					$	2,362
Deferred Cost of Employee Benefit Plans,
net of taxes $(4)										$	(7	)		(7	)
Capital Contributions From Parent						9								9
Earnings Available for Common Shareholder								227						227
Cash Dividends Declared								(134	)					(134	)
Balance at December 31, 2006		40		571		778		1,115			(7	)		2,457
Comprehensive Income (Loss):
Earnings Available for Common Shareholder								238						238
Deferred Cost of Employee Benefit Plans,
net of taxes $(1)											(1	)		(1	)
Total Comprehensive Income (Loss)								238			(1	)		237
Capital Contributions From Parent						76								76
Cash Dividends Declared								(148	)					(148	)
Balance at December 31, 2007		40		571		854		1,205			(8	)		2,622
Comprehensive Income (Loss):
Earnings Available for Common Shareholder								266						266
Deferred Cost of Employee Benefit Plans,
net of taxes $(24)											(38	)		(38	)
Total Comprehensive Income (Loss)								266			(38	)		228
Capital Contributions From Parent						15								15
Cash Dividends Declared								(161	)					(161	)
Balance at December 31, 2008		40	$	571	$	869	$	1,310		$	(46	)	$	2,704

(a) $4.50 par value, authorized 50 million shares

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

South Carolina Electric & Gas Company (SCE&G, and together with its consolidated affiliates, the Company), a public utility, is a South Carolina corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation (SCANA), a South Carolina corporation. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

The accompanying Consolidated Financial Statements reflect the accounts of SCE&G, South Carolina Fuel Company, Inc. (Fuel Company) and South Carolina Generating Company, Inc. (GENCO). Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.

Financial Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46), “Consolidation of Variable Interest Entities,” requires an enterprise’s consolidated financial statements to include entities in which the enterprise has a controlling financial interest. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company, and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, the Company’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as minority interest in the Company’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 615 megawatt net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase agreement and related operating agreement. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $437 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances. See also Note 5.

B. Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (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 certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded the regulatory assets and regulatory liabilities summarized as follows.

	December 31,
Millions of dollars	2008		2007
Regulatory Assets:
Accumulated deferred income taxes	$	166	$	156
Environmental remediation costs		19		17
Asset retirement obligations and related funding		250		264
Franchise agreements		50		52
Deferred employee benefit plan costs		325		109
Other		44		31
Total Regulatory Assets	$	854	$	629

Regulatory Liabilities:
Accumulated deferred income taxes	$	30	$	32
Other asset removal costs		503		472
Storm damage reserve		48		49
Planned major maintenance		11		15
Other		16		41
Total Regulatory Liabilities	$	608	$	609

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Environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates. SCE&G is authorized to amortize $1.4 million of these costs annually.

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

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

The SCPSC or the United States Federal Energy Regulatory Commission (FERC) has reviewed and approved through specific orders most of the items or by FERC shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by the SCPSC or by FERC. 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 SCE&G. However, ultimate recovery of these costs is subject to regulatory approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C. Utility Plant and Major Maintenance

SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) jointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G’s portion of Summer Station was approximately $1.0 billion as of December 31, 2008 and 2007 (including amounts related to ARO). Accumulated depreciation associated with SCE&G’s share of Summer Station was $527.6 million and $513.1 million as of December 31, 2008 and 2007, respectively (including amounts related to ARO). SCE&G’s share of the direct expenses associated with operating Summer Station is included in other operation and maintenance expenses and totaled $87.4 million in 2008, $86.7 million in 2007 and $77.5 million in 2006.

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Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, SCE&G collects $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2008, the Company incurred $7.7 million for turbine maintenance. The remaining balance is in a regulatory liability account on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage upon completion of the preceding outage. SCE&G accrued $1.0 million per month from July 2005 through December 2006 for its portion of the outage in the fall of 2006, accrued $1.1 million per month from January 2007 through June 2008 for its portion of the outage in the spring of 2008, and is accruing $1.2 million per month for its portion of the outage scheduled for the fall of 2009. Total costs for the 2006 outage were $25.8 million, of which SCE&G was responsible for $17.2 million. Total costs for the 2008 outage were $25.7 million, of which SCE&G was responsible for $17.1 million. As of December 31, 2008 and 2007, SCE&G had an accrued balance of $7.3 million and $12.7 million, respectively.

D. Allowance for Funds Used During Construction (AFC)

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 6.0% for 2008, 5.8% for 2007 and 5.0% for 2006. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

E. Revenue Recognition

The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $97.1 million and $92.8 million as of December 31, 2008 and 2007, respectively.

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 hearing. In addition, included in these amounts are realized and unrealized gains and losses incurred in the Company’s natural gas hedging program.

The Company’s gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment which minimizes fluctuations in gas revenues due to abnormal weather conditions.

F. Depreciation and Amortization

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

G. Nuclear Decommissioning

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

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Under the Company’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2008, 2007 and 2006) are invested in insurance policies on the lives of certain Company and affiliate personnel. The Company transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest on proceeds, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

H. Income and Other Taxes

The Company is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including the Company, in the form of capital contributions. The Company received capital contributions under such provisions of $1.8 million in 2008 and $8.6 million in 2007.

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

J. Environmental

K. Cash and Cash Equivalents

L. Commodity Derivatives

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

M. New Accounting Matters

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SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements,” was issued in December 2007. SFAS 160 requires entities to report noncontrolling (minority) interests in subsidiaries as equity. SFAS 160 is effective for fiscal years beginning after December 15, 2008. Initial adoption of SFAS 160 is not expected to significantly affect the Company’s results of operations, cash flows or financial position.

FASB Staff Position FAS 132(R), “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)), was issued on December 30, 2008. FSP FAS 132(R), amends SFAS 132(R) to require enhanced disclosures about an employer’s plan assets in a defined benefit pension plan or other postretirement plan. The disclosures required, similar to those required under SFAS 157, include a discussion on the inputs and valuation techniques used to develop fair value measurements of plan assets. In addition, the fair value of each major category of plan assets is required to be disclosed separately for pension plans and other postretirement benefit plans. FSP FAS 132(R) is effective for fiscal years ending after December 15, 2009. Initial adoption of FSP FAS 132(R) is not expected to affect the Company’s results of operations, cash flows or financial position.

N. Affiliated Transactions

Carolina Gas Transmission Corporation (CGTC) transports natural gas to the Company to supply certain electric generation requirements and to serve SCE&G’s retail gas customers. The Company had approximately $0.7 million in receivables, related to certain transportation refunds, from CGTC and $1.5 million payable to CGTC for transportation services at December 31, 2008 and 2007, respectively.

The Company purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating Station, Urquhart Electric Generation Station and to serve its retail gas customers. Such purchases totaled approximately $290.5 million in 2008, $208.9 million in 2007 and $114.5 million in 2006. SCE&G’s payables to SEMI for such purposes were $11.1 million and $12.0 million as of December 31, 2008 and 2007, respectively.

The Company held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel. The partnerships ceased operations in 2007 as a result of the expiration of the synthetic fuel tax credits program at the end of 2007, and they were dissolved in 2008. The Company’s receivables from these affiliated companies were $28.8 million and payables to these affiliated companies were $26.9 million at December 31, 2007. The Company purchased synthetic fuel from these affiliated companies of $281.6 million in 2007 and $291.1 million in 2006. The Company made cash investments in these affiliated companies of $2.2 million in 2008, $16.2 million in 2007 and $18.4 million in 2006.

The Company participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. The Company incurred interest expense on money pool borrowings of $4.2 million in 2008 and 2007. The Company had a net receivable of $9.1 million and an accounts payable of $118.9 million at December 31, 2008 and 2007, respectively.

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In 2006, the Company purchased LNG facilities and LNG inventory from SCPC for approximately $17.1 million and $17.2 million, respectively. The Company also purchased underground gas storage inventory from SCPC for approximately $40.3 million.

O. Use of Estimates

P. Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, comprised of the deferred cost of employee benefit plans, totaled $46.2 million and $7.9 million as of December 31, 2008 and 2007, respectively.

2. RATE AND OTHER REGULATORY MATTERS

Electric

On March 31, 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). The COL, if approved, would authorize SCE&G and Santee Cooper to build and operate the nuclear generating units referred to above. The NRC’s review process is expected to last approximately three to four years. Construction could begin shortly thereafter, with a projected in-service date of 2016 for the first unit.

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Gas

In October 2007 the SCPSC approved an increase in retail natural gas base rates of 0.9% under the terms of the RSA. The rate adjustment was effective with the first billing cycle in November 2007.

SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G's rates are calculated using a methodology which adjusts the cost of gas monthly based on a twelve-month rolling average.

3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

The Company participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA’s policy has been to fund the Plan to the extent permitted by applicable federal income tax regulations as determined by an independent actuary.

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

In addition to pension benefits, the Company participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to active and retired employees. Retirees share in a portion of their medical care cost. SCANA provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.

For the years ended December 31, 2008, 2007 and 2006, the Company’s net periodic benefit income for the pension plan was $18.3 million, $20.0 million and $16.0 million, respectively, for the pension plan and net periodic benefit cost was $13.0 million, $12.8 million and $14.3 million, respectively, for the postretirement plan.

Share-Based Compensation

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

SFAS 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $4 million (net of taxes) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.

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Liability Awards

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

Beginning with the 2007-2009 performance cycle, the Plan provides for performance measurement and award determination on an annual basis (rather than the above described three-year measurement and determination), with payment of awards being deferred until after the end of the three-year performance cycle. Accordingly, payouts under the 2007 three-year cycle will be earned for each year that performance goals are met during the three-year cycle, though payments will be deferred until the end of the cycle and will be contingent upon the participants still being employed by SCANA at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.

In the 2008-2010 performance cycle, 20% of the performance award was granted in the form of restricted (nonvested) shares, which are equity awards more fully further described below. The remaining 80% of the award was made in performance shares. The payment of performance shares for the 2008-2010 performance cycle will be based on SCANA’s performance against pre-determined measures of TSR (weighted 50%) and the growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%).

Under SFAS 123(R), compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities were paid totaling $0.4 million in 2008 and $1.2 million in 2006. No such payments were made in 2007.

Fair value adjustments for performance awards resulted in an increase to compensation expense recognized in the statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $10.7 million for the year ended December 31, 2008 and $3.8 million for the year ended December 31, 2007, compared to a reduction to compensation expense totaling $(4.8) million for the year ended December 31, 2006. Fair value adjustments resulted in capitalized compensation costs of $1.8 million during the year ended December 31, 2008 and $0.7 million in 2007, compared to a net credit to capitalized compensation costs of $(0.7) million in 2006.

Equity Awards

A summary of activity related to nonvested shares follows:

		Weighted Average
		Grant-Date
Nonvested Shares	Shares	Fair Value
Nonvested at January 1, 2008	-	$	-
Granted	75,824		37.33
Vested	-		-
Forfeited	1,236		37.35
Nonvested at December 31, 2008	74,588		37.33

Nonvested shares are granted at a price corresponding to the opening price of SCANA common stock on the date of the grant. The Company expensed compensation costs for nonvested shares of $0.1 million in 2008. Tax benefits and capitalized compensation costs in 2008 were not significant.

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A summary of activity related to nonqualified stock options follows:

Stock Options	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2005		439,270		$	27.53
Exercised		(53,330	)		27.52
Outstanding-December 31, 2006		385,940			27.56
Exercised		(258,756	)		27.62
Outstanding-December 31, 2007		127,184			27.45
Exercised		(20,720	)		27.49
Outstanding-December 31, 2008		106,464			27.44

The exercise of stock options during 2006-2008 was satisfied using a combination of original issue shares and open market purchases of SCANA’s common stock. SCANA realized $0.6 million, $7.1 million and $1.5 million in cash upon the exercise of options in the years ended December 31, 2008, 2007 and 2006, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $0.1 million, $1.5 million and $0.3 million were credited to SCANA’s additional paid in capital (common equity) in these periods.

4. LONG-TERM DEBT

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

			2008					2007
Dollars in millions	Maturity		Balance		Rate			Balance		Rate
First Mortgage Bonds (secured)	2009-2038	$	2,335		6.07	%	$	1,675		6.00	%
GENCO Notes (secured)	2011-2024		276		5.95	%		119		5.86	%
Industrial and Pollution Control Bonds (a)	2012-2038		228		4.63	%		156		5.24	%
Borrowings Under Credit Agreements	2011		285		1.61	%		-
Other	2009-2027		62					73
Total debt			3,186					2,023
Current maturities of long-term debt			(140	)				(13	)
Unamortized discount			(13	)				(7	)
Total long-term debt, net		$	3,033				$	2,003

(a) Includes $71.4 million of variable rate debt hedged by fixed rate swaps in 2008.

The annual amounts of long-term debt maturities for the years 2009 through 2013 are summarized as follows:

Year	Millions of dollars

2009	$	140
2010		17
2011		456
2012		17
2013		163

Substantially all of SCE&G's and GENCO's electric utility plant is pledged as collateral in connection with long-term debt. In addition, in the event that GENCO’s title to its land were deemed to be defective, SCE&G would be required to repay GENCO’s notes.

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5. LINES OF CREDIT AND SHORT-TERM BORROWINGS

At December 31, 2008 and 2007, SCE&G (including Fuel Company) had available the follow lines of credit and short-term borrowings outstanding:

Millions of dollars	2008			2007
Lines of credit:
Committed long-term (expire December 2011)
Total	$	650		$	650
Outstanding bank loans		285			-
Weighted average interest rate		1.61	%		-
Outstanding commercial paper (270 or fewer days) (a)	$	34		$	464
Weighted average interest rate		5.69	%		5.74	%
Uncommitted (b):
Total	$	78		$	78
Used by SCANA		-			7
Weighted average interest rate		-			5.10	%

(a) The Company’s committed lines of credit serve to back-up the issuance of commercial paper or to provide liquidity support.

Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term

commercial paper or bank loans

(b) SCE&G, SCANA or a combination may use the line of credit.

The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wachovia Bank, National Association and Bank of America, N. A. each provide 14.3% of the aggregate $650 million credit facilities, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%. Four other banks provide the remaining 9.6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company). In addition, a portion of the credit facilities supports SCANA’s borrowing needs. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

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

SCE&G and Fuel Company have commercial paper programs in the amount of $350 million and $250 million, respectively. SCE&G has guaranteed the short-term borrowings of Fuel Company.

6. RETAINED EARNINGS

SCE&G’s Restated Articles of Incorporation and its bond indenture each contain provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock.

With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2008, $56 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

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7. PREFERRED STOCK

Par Value	Authorized	Available for Issuance
$100	1,000,000	-
$50	575,176	300,000
$25	2,000,000	2,000,000

Preferred Stock (Not subject to purchase or sinking funds)

Preferred Stock (Subject to purchase or sinking funds)

Changes in “Total Preferred Stock (Subject to purchase or sinking funds)” during 2008, 2007 and 2006 are summarized as follows:

	Series
	4.50%, 4.60% (A) & 5.125%			4.60% (B) & 6.00%			Total Shares			Millions of Dollars
Redemption Price	$51.00			$50.50
Balance at December 31, 2005		77,043			99,361			176,404		$	8.8
Shares Redeemed-$50 par value		(2,608	)		(6,600	)		(9,208	)		(0.5	)
Balance at December 31, 2006		74,435			92,761			167,196			8.3
Shares Redeemed-$50 par value		(4,600	)		(4,629	)		(9,229	)		(0.4	)
Balance at December 31, 2007		69,835			88,132			157,967			7.9
Shares Redeemed-$50 par value		(4,600	)		(3,400	)		(8,000	)		(0.4	)
Balance at December 31, 2008		65,235			84,732			149,967		$	7.5

8. INCOME TAXES

Total income tax expense (benefit) attributable to income (before cumulative effect of accounting change) for 2008, 2007 and 2006 is as follows:

Millions of dollars	2008			2007			2006
Current taxes:
Federal	$	32		$	63		$	70
State		3			9			5
Total current taxes		35			72			75
Deferred taxes, net:
Federal		111			34			9
State		13			4			5
Total deferred taxes		124			38			14
Investment tax credits:
Deferred-state		5			5			5
Amortization of amounts deferred-state		(3	)		(3	)		(3	)
Amortization of amounts deferred-federal		(3	)		(3	)		(3	)
Total investment tax credits		(1	)		(1	)		(1	)
Total income tax expense	$	158		$	109		$	88

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Millions of dollars	2008			2007			2006
Net income	$	273		$	245		$	230
Income tax expense		158			109			88
Minority interest		9			7			7
Total pre-tax income	$	440		$	361		$	325
Income taxes on above at statutory federal income tax rate	$	154		$	126		$	114
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		12			10			8
Synthetic fuel tax credits		-			(17	)		(34	)
Non-taxable recovery of Lake Murray back-up dam project carrying costs		(2	)		(2	)		(2	)
Amortization of federal investment tax credits		(3	)		(3	)		(3	)
Domestic production activities deduction		(1	)		(4	)		(1	)
Other differences, net		(2	)		(1	)		6
Total income tax expense	$	158		$	109		$	88

The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $890 million at December 31, 2008 and $815 million at December 31, 2007 are as follows:

Millions of dollars	2008		2007
Deferred tax assets:
Nondeductible reserves	$	83	$	91
Unamortized investment tax credits		51		51
Deferred compensation		10		15
Unbilled revenue		13		12
Pension plan income		18		-
Other		53		15
Total deferred tax assets		228		184
Deferred tax liabilities:
Property, plant and equipment		901		830
Pension plan income		-		87
Deferred employee benefit plan costs		125		43
Deferred fuel costs		51		2
Other		41		37
Total deferred tax liabilities		1,118		999
Net deferred tax liability	$	890	$	815

The Company is included in the consolidated federal income tax return of SCANA and files various applicable state income tax returns. The Internal Revenue Service (IRS) has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2004 are closed for additional assessment. With few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2005.

In June 2008, the Company received an unfavorable decision in its litigation of a state tax issue, which denied the Company a refund of state income tax. Although the decision was rendered by the court of last resort, the Company requested and was granted a rehearing of the case by that court in November 2008. It is reasonably possible that the rehearing could result in a favorable decision to be rendered within twelve months. In 2007, the Company removed $15 million of previously recorded tax benefit from its balance sheet related to this item, in connection with the initial adoption of FIN 48, “Accounting for Uncertainty in Income Taxes.” As a result, the unfavorable decision has had no impact on the Company’s results of operations, cash flows or financial position. If the rehearing is decided in favor of the Company, any change to the unrecognized tax benefit will be within a range of $0 to $15 million. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $15 million. However, the impact on any individual year’s effective tax rate would be immaterial, because any tax benefit recorded would be amortized into earnings over a number of years under SFAS 71. No other material changes in the status of the Company’s tax positions have occurred through December 31, 2008.

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A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

	Unrecognized
Millions of dollars	Tax Benefit
Balance at January 1, 2008	$	15
Additions based on tax positions related to the current year		-
Additions for tax positions of prior years		-
Reductions for tax positions of prior years		-
Settlements		-
Balance at December 31, 2008	$	15

9. FINANCIAL INSTRUMENTS

	2008				2007
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,173.2	$	3,297.1	$	2,016.0	$	2,023.9
Preferred stock (subject to purchase or sinking funds)		7.5		7.5		7.9		7.0

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

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

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

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

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

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

The Company uses interest swap agreements to manage interest rate risk on certain debt instruments. At December 31, 2008 the fair value of the Company’s interest rate swaps designated as cash flow hedges totaled $48.2 million (loss) related to notional amounts of $221.4 million.

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Fair Value Measurement

The Company values commodity derivative assets and liabilities using unadjusted NYMEX prices, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using broker quotes.

At December 31, 2008, fair value measurements, and the level within the fair value hierarchy of SFAS 157 in which the measurements fall, were as follows:

	Fair Value Measurements at December 31, 2008 Using
Millions of dollars	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets - Derivative instruments	$	6	$	14		-
Liabilities - Derivative instruments		2		60		-

10. COMMITMENTS AND CONTINGENCIES

A. Nuclear Insurance

B. Environmental

The United States Environmental Protection Agency (EPA) issued a final rule in 2005 known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008 the United States Court of Appeals for the District of Columbia Circuit remanded the rule without vacatur. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements, including the installation of selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction and wet limestone scrubbers at both Wateree and Williams Stations for sulfur dioxide reduction. SCE&G and GENCO have already begun to install this equipment, and expect to incur capital expenditures totaling approximately $559 million through 2010. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this vacated rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In 2005 the EPA issued the Clean Air Mercury Rule (CAMR) which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule. On February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. The Company expects the EPA will issue a new mercury emissions rule but cannot predict when such a rule will be issued or what requirements it will impose.

C. Claims and Litigation

In May 2004, a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims. SCANA and SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted SCANA’s and SCE&G’s motion to dismiss and issued an order dismissing the case in June 2005. The plaintiff appealed to the South Carolina Supreme Court. The Supreme Court reversed the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration. In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to owners of easements situated in Charleston County, South Carolina. The South Carolina Court of Appeals dismissed the plaintiff’s appeal of this ruling, determining that the Circuit Court ruling was not immediately appealable. On February 27, 2008 the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County. In July 2008, the plaintiff’s motion to add SCANA Communications, Inc. (SCI) to the lawsuit as an additional defendant was granted. The parties filed motions for partial summary judgment, and the plaintiff moved to expand the class. In December 2008 these motions were heard and denied by the Court. Trial is not anticipated before the fall of 2009. SCANA, SCI and SCE&G will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.

D. Nuclear Generation

On May 27, 2008, SCE&G and Santee Cooper announced that they had entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of V. C. Summer Nuclear Station. SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent. Assuming timely receipt of federal and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. SCE&G’s share of the estimated cash outlays (future value) totals $5.3 billion for plant costs and $646 million for related transmission infrastructure costs.

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E. 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 $12.7 million, $15.8 million and $12.8 million in 2008, 2007 and 2006, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2009	$	15
2010		6
2011		6
2012		4
2013		3
Total	$	34

F. Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended for coal supply, nuclear fuel contracts, construction projects and other commitments totaled $949.82 million, $728.3 million and $526.0 million in 2008, 2007 and 2006, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2009	$	1,021
2010		463
2011		336
2012		13
2013		14
Thereafter		47
Total	$	1,894

G. Asset Retirement Obligations

SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation and relates primarily to the Company’s regulated utility operations. As of December 31, 2008, the Company has recorded an ARO of approximately $105 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $332 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

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

Millions of dollars	2008			2007
Beginning balance	$	294		$	279
Liabilities incurred		-			-
Liabilities settled		(1	)		(1	)
Accretion expense		16			16
Revisions in estimated cash flows		128			-
Ending Balance	$	437		$	294

Revisions in estimated cash flows in 2008 related to the expectation of higher costs associated with coal ash disposal than had been assumed in the prior cash flow analysis.

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11. SEGMENT OF BUSINESS INFORMATION

The Company’s reportable segments are Electric Operations and Gas Distribution. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.

Electric Operations is primarily engaged in the generation, transmission, and distribution of electricity, and is regulated by the SCPSC and FERC. Gas Distribution is engaged in the purchase and sale, primarily at retail, of natural gas, and is regulated by the SCPSC.

Disclosure of Reportable Segments (Millions of dollars)

2008		Electric Operations		Gas Distribution		Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	2,248	$	568		-		$	2,816
Intersegment Revenue		-		4	$	(4	)		-
Operating Income (Loss)		523		40		(4	)		559
Interest Expense		15		-		140			155
Depreciation and Amortization		254		20		(9	)		265
Segment Assets		6,602		529		1,921			9,052
Expenditures for Assets		859		64		(176	)		747
Deferred Tax Assets		n/a		n/a		n/a			n/a

2007
Customer Revenue	$	1,962	$	519		-		$	2,481
Intersegment Revenue		-		6	$	(6	)		-
Operating Income (Loss)		464		41		(7	)		498
Interest Expense		16		-		125			141
Depreciation and Amortization		257		19		-			276
Segment Assets		5,925		480		1,572			7,977
Expenditures for Assets		540		51		28			619
Deferred Tax Assets		n/a		n/a		5			5

2006
Customer Revenue	$	1,886	$	505		-		$	2,391
Intersegment Revenue		-		3	$	(3	)		-
Operating Income (Loss)		456		25		(13	)		468
Interest Expense		15		-		125			140
Depreciation and Amortization		268		18		-			286
Segment Assets		5,520		440		1,666			7,626
Expenditures for Assets		304		83		25			412
Deferred Tax Assets		n/a		n/a		19			19

Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments. As a result, the Company does not allocate interest charges, income tax expense or assets other than utility plant to its segments. Interest income is not reported by segment and is not material. In accordance with SFAS 109, the Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

The Consolidated Financial Statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Segment Assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include the totals from the Company that are not allocated to the segments. Expenditures for Assets are adjusted for revisions to estimated cash flows related to asset retirement obligations, and totals not allocated to other segments.

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

2008 Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues		693		698		776		649		2,816
Operating income		125		127		190		117		559
Net income		59		60		100		54		273

2007 Millions of dollars
Total operating revenues	$	633	$	575	$	686	$	587	$	2,481
Operating income		81		109		188		120		498
Net income		38		54		99		54		245

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PART II,

ITEMS 9, 9A AND 9A(T),

PART III

AND

PART IV

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SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2008, an evaluation was performed under the supervision and with the participation of SCANA's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCANA's disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCANA's management, including the CEO and CFO, concluded that SCANA's disclosure controls and procedures were effective as of December 31, 2008. There has been no change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2008 that has materially affected or is reasonably likely to materially affect SCANA's internal control over financial reporting.

Management's Evaluation of Internal Control Over Financial Reporting:

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2008, the effectiveness of such structure and procedures. This management report follows.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCANA Corporation (SCANA) is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA's internal control system was designed by or under the supervision of SCANA’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), to provide reasonable assurance to SCANA's management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.

SCANA's management assessed the effectiveness of SCANA's internal control over financial reporting as of December 31, 2008. In making this assessment, SCANA used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, SCANA's management believes that, as of December 31, 2008, internal control over financial reporting is effective based on those criteria.

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

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ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

SCANA Corporation

We have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2008, of the Company and our report dated February 27, 2009, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/DELOITTE & TOUCHE LLP

Columbia, South Carolina

February 27, 2009

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ITEM 9A(T). CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2008, an evaluation was performed under the supervision and with the participation of SCE&G's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that SCE&G's disclosure controls and procedures were effective as of December 31, 2008. There has been no change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2008 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting.

Management's Evaluation of Internal Control Over Financial Reporting:

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of South Carolina Electric & Gas Company (SCE&G) is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G's internal control system was designed by or under the supervision of SCE&G’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), to provide reasonable assurance to SCE&G's management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

SCE&G's management assessed the effectiveness of SCE&G's internal control over financial reporting as of December 31, 2008. In making this assessment, SCE&G used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, SCE&G's management believes that, as of December 31, 2008, internal control over financial reporting is effective based on those criteria.

This annual report does not include an attestation report of SCE&G’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SCE&G’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit SCE&G to provide only its management’s report in this annual report.

ITEM 9B. OTHER INFORMATION

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

SCANA: A list of SCANA's executive officers is in Part I of this annual report at page 24. The other information required by Item 10 is incorporated herein by reference to the captions "NOMINEES FOR DIRECTORS," "CONTINUING DIRECTORS," "BOARD MEETINGS-COMMITTEES OF THE BOARD," "GOVERNANCE INFORMATION - SCANA's Code of Conduct & Ethics" and "OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy statement for the 2009 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA's fiscal year.

CODE OF ETHICS

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

The full text of the Code is published on the SCANA website, at www.scana.com, under the “Company Profile - Code of Conduct” caption, and a copy is also available in print upon request to the Corporate Secretary, SCANA Corporation, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201. SCANA intends to disclose future amendments to, or waivers from, certain provisions of the Code on its website within two business days following the date of such amendment or waiver.

DIRECTORS

The directors listed below were elected April 24, 2008 to hold office until the next annual meeting of SCE&G's shareholders to be held on April 23, 2009. Each of the directors is also a director of SCANA. There are no family relationships among any of SCE&G's directors and executive officers.

	W. Hayne Hipp (Age 69) Director since 1983

	Mr. Hipp has been a private investor since The Liberty Corporation’s acquisition in January 2006. Prior to its acquisition, Mr. Hipp served as Chairman, Chief Executive Officer and a director of the Liberty Corporation, a broadcasting holding company headquartered in Greenville, South Carolina. Mr. Hipp held these positions for more than five years. Mr. Hipp’s term will expire at the Annual Meeting in 2009 when he reaches the mandatory retirement age.

	Harold C. Stowe (Age 62)* Director since 1999

	Mr. Stowe retired as interim Dean of the Wall College of Business at Coastal Carolina University in Conway, South Carolina on July 1, 2007, a position that he held since June 2006. From February 2005 to May 2006, Mr. Stowe was retired. Prior to his retirement, Mr. Stowe had served as President of Canal Holdings, LLC, a forest products industry company, located in Conway, South Carolina, and its predecessor company, since March 1997. Mr. Stowe is a director of Ruddick Corporation, in Charlotte, North Carolina.

	G. Smedes York (Age 68) Director since 2000

	Mr. York is Chairman of York Properties, Inc., a full-service commercial and residential real estate company, in Raleigh, North Carolina. Mr. York has been associated with York Properties, Inc. since 1970. Mr. York is also Chairman of the Board of Prudential York Simpson Underwood, a residential real estate brokerage company, and of McDonald-York, Inc., a general contractor, both in Raleigh, North Carolina.

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		Bill L. Amick (Age 65) Director since 1990

		Mr. Amick has been the Chairman of The Amick Company, a residential and resort property real estate development company, since his retirement in October 2006 from Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., a vertically integrated broiler operation. Prior to his retirement, he served as Chairman of the Board of the Amick entities, all of which are located in Batesburg, South Carolina. He held those positions for more than five years. Mr. Amick is a director of Blue Cross and Blue Shield of South Carolina.

		Sharon A. Decker (Age 52) Director since 2005

		Mrs. Decker is the founder and has been the principal of The Tapestry Group, a faith-based, non-profit organization, located in Rutherfordton, North Carolina, since September 2004. Mrs. Decker previously served as President of Tanner Holdings, LLC and Doncaster, apparel manufacturers, from August 1999 until September 2004. Mrs. Decker is a director of Coca-Cola Bottling Company Consolidated, Inc. and Family Dollar Stores, Inc., both in Charlotte, North Carolina.

		D. Maybank Hagood (Age 47)* Director since 1999

		Mr. Hagood has been President and Chief Executive Officer of Southern Diversified Distributors, Inc., a provider of logistic and distribution services, located in Charleston, South Carolina, since November 2003. Mr. Hagood also has been President and Chief Executive Officer of William M. Bird and Company, Inc., a subsidiary of Southern Diversified Distributors, Inc., a wholesale distributor of floor covering materials, in Charleston, South Carolina, since 1993.

		William B. Timmerman (Age 62) Director since 1991

		Mr. Timmerman has been Chairman of the Board and Chief Executive Officer of SCANA since March 1997. He has been President of SCANA since December 1995.

	James A. Bennett (Age 48) Director since 1997

	Mr. Bennett has been Executive Vice President and Director of Public Affairs of First Citizens Bank, located in Columbia, South Carolina, since August 2002. Previously, he was President and Chief Executive Officer of South Carolina Community Bank, in Columbia, South Carolina, from May 2000 to July 2002.

	James M. Micali (Age 60) Director since 2007

	Mr. Micali was Chairman and President of Michelin North America, Inc, located in Greenville, South Carolina, from 1996 until August 2008, and he continues to consult for Michelin. Mr. Micali is also of counsel to the law firm Ogletree Deakins LLC in Greenville, South Carolina, and a Senior Advisor to the General Partner of Azalea Fund III of Azalea Capital LLC (a private equity firm), also in Greenville, South Carolina. Mr. Micali has served as a director of Sonoco Products Company, in Hartsville, South Carolina since 2003. Mr. Micali served as the Chairman of the South Carolina Chamber of Commerce in 2008. Mr. Micali also serves on the board of Ritchie Bros. Auctioneers in Vancouver, Canada, and on the board of American Tire Distributors in Charlotte, North Carolina.

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	Lynne M. Miller (Age 57) Director since 1997

	Ms. Miller co-founded Environmental Strategies Corporation, an environmental consulting firm in Reston, Virginia in 1986, and served as President from 1986 until 1995, and as Chief Officer from 1995 until September 2003 when the firm was acquired by Quanta Capital Holdings, Inc., a specialty insurer, and its name was changed to Environmental Strategies Consulting LLC. Ms Miller has been an environmental consultant since her retirement from Quanta Capital Holdings, Inc. in August 2006. From August 2005 to August 2006, she was a Senior Business Consultant at Quanta Capital Holdings. From April 2004 through July 2005, she was President of Quanta Technical Services LLC. She was Chief Executive Officer of Environmental Strategies Consulting LLC, a division of Quanta Technical Services LLC, from September 2003 through March 2004. Ms. Miller served as a director of Adams National Bank, a subsidiary of Abigail Adams National Bancorp, Inc., in Washington, D.C. until October 2008.

	James W. Roquemore (Age 54)* Director since 2007

	Mr. Roquemore is Chief Executive Officer and Chairman of Patten Seed Company, headquartered in Lakeland, Georgia, and General Manager of Super-Sod/Carolina, a company that produces and markets turf grass, sod and seed. He has held these positions for more than five years. Mr. Roquemore is a director of South Carolina Bank and Trust, N. A. and SCBT Financial Corporation. He serves on the Southeast Region and National boards of the Boy Scouts of America. He is currently the Agribusiness Co-Chairman for “New Carolina” –South Carolina’s Council on Competitiveness, and is the past President and current board member of the Palmetto Agribusiness Council.

	Maceo K. Sloan (Age 59)* Director since 1997

	Mr. Sloan is Chairman, President and Chief Executive Officer of Sloan Financial Group, Inc., a financial holding company, and Chairman, Chief Executive Officer and Chief Investment Officer of both NCM Capital Management Group, Inc., and NCM Capital Advisers, Inc., investment management companies, in Durham, North Carolina. He has held these positions for more than five years. Mr. Sloan is Chairman of the College Retirement Equities Fund (CREF) Board of Trustees. Mr. Sloan served as Chairman of the Board of M&F Bancorp, Inc. and as a director of its subsidiary, Mechanics and Farmers Bank, in Durham, North Carolina, until December 2008.

*SCE&G has a separately-designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act, members of which are indicated by an asterisk. SCE&G’s board of directors has determined that Mr. Stowe is an audit committee financial expert as defined under Item 407 (d)(5) of the Securities and Exchange Commission's Regulation S-K. SCE&G’s board of directors has also determined that Mr. Stowe is independent as defined by the New York Stock Exchange Listing Standards.

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EXECUTIVE OFFICERS

SCE&G's officers are elected at the annual organizational meeting of the Board of Directors and hold office until the next such organizational meeting, unless (1) a resignation is submitted, (2) the Board of Directors shall otherwise determine, or (3) as provided in the By-laws of SCE&G.

Name	Age	Positions Held During Past Five Years	Dates
W. B. Timmerman	62	Chairman of the Board and Chief Executive Officer	*-present
J. E. Addison	48	Senior Vice President and Chief Financial Officer Vice President – Finance	2006-present *-2006
J. C. Bouknight	56	Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA	2004-present *-2004
S. D. Burch	51	Senior Vice President-Fuel Procurement and Asset Management	*-present
S. A. Byrne	49	Senior Vice President-Generation, Nuclear and Fossil Hydro Senior Vice President-Nuclear Operations	2004-present *-2004
K. B. Marsh	53	President and Chief Operating Officer Senior Vice President and Chief Financial Officer	2006-present *-2006
F. P. Mood, Jr.	71	Senior Vice President, General Counsel and Assistant Secretary Attorney, Haynsworth Sinkler Boyd, P.A.	2005-present *-2005

* Indicates position held at least since March 1, 2004

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

All of SCE&G's common stock is held by its parent, SCANA Corporation. The required forms indicate that no equity securities of SCE&G are owned by its directors and officers. Based solely on a review of the copies of such forms and amendments furnished to SCE&G and written representations from its officers and directors, SCE&G believes that its officers, directors and greater than 10% beneficial owners complied with all applicable Section 16(a) filing requirements during 2008.

ITEM 11. EXECUTIVE COMPENSATION

SCANA: The information required by Item 11 is incorporated herein by reference to the captions “COMPENSATION DISCUSSION AND ANALYSIS,” “COMPENSATION COMMITTEE REPORT,” “SUMMARY COMPENSATION TABLE,” “2008 GRANTS OF PLAN-BASED AWARDS” “OUTSTANDING EQUITY AWARDS AT 2008 FISCAL YEAR END,” “2008 OPTION EXERCISES AND STOCK VESTED,” “PENSION BENEFITS,” “2008 NONQUALIFIED DEFERRED COMPENSATION,” “POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL,” and “DIRECTOR COMPENSATION” under the heading “EXECUTIVE COMPENSATION” in SCANA's definitive proxy statement for the 2009 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA's fiscal year.

SCE&G: For purposes of this section, references herein to "we," "our" or "us" shall mean South Carolina Electric & Gas Company and references to the "Company" shall mean SCANA Corporation and its consolidated subsidiaries, unless the context would indicate otherwise.

EXECUTIVE COMPENSATION

Compensation Committee Processes and Procedures

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

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

The Committee has the authority under its charter to retain, approve fees for, and terminate advisors, consultants and others as it deems appropriate to assist in the fulfillment of its responsibilities. The Committee has, however, historically chosen to use relevant information provided to us by management’s consultant, Hewitt Associates. The Committee uses this information to assist it in carrying out its responsibilities for overseeing matters relating to compensation plans and compensation of our senior executive officers. Using information provided by a national compensation consultant helps to assure the Committee that our policies for compensation and benefits are competitive and aligned with utility and general industry practices.

Compensation Committee Interlocks and Insider Participation

During 2008, decisions on various elements of executive compensation were made by the Human Resources Committee. No officer, employee, former officer or any related person of SCANA or SCE&G or any of their respective subsidiaries served as a member of the Human Resources Committee.

The directors who served on the Human Resources Committee during 2008 were:

Mr. G. Smedes York, Chairman

Mr. James A. Bennett

Mrs. Sharon A. Decker

Mr. D. Maybank Hagood

Mr. James M. Micali

Ms. Lynne M. Miller

Mr. James W. Roquemore

Mr. Maceo K. Sloan

Compensation Discussion and Analysis

Objectives and Philosophy of Executive Compensation

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

·	Hiring and retaining premier executive talent;

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

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

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

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

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

Principal Components of Executive Compensation

During 2008, senior executive compensation consisted primarily of three key components: base salary, short-term cash incentive compensation, including a discretionary bonus (under the Short-Term Annual Incentive Plan) and long-term equity-based incentive compensation (under the SCANA shareholder-approved Long-Term Equity Compensation Plan). We also provide various additional benefits to senior executive officers, including health, life and disability insurance plans, retirement plans, termination, severance and change in control arrangements, and limited perquisites. The Human Resources Committee makes its decisions about how to allocate senior executive officer compensation among base salary, short-term cash incentive compensation and long-term equity-based incentive compensation on the basis of market information and analysis provided by our compensation consultant, and our goals of remaining competitive with the compensation practices of a group of surveyed companies and of linking compensation to our corporate performance and individual senior executive officer performance.

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

SCANA sponsors the Short-Term Annual Incentive Plan and Long-Term Equity Compensation Plan which are available to eligible senior executive officers of SCE&G. These plans are referred to herein as “our” plans.

Factors Considered in Setting Senior Executive Officer Compensation

Use of Market Surveys and Peer Group Data

We believe it is important to consider comparative market information about compensation paid to executive officers of other companies in order to remain competitive in the executive workforce marketplace. We want to be able to attract and retain highly skilled and talented senior executive officers who have the ability to carry out our short- and long-term goals. To do so, we must be able to compensate them at levels that are competitive with compensation offered by other companies in our business or geographic marketplace that seek similarly skilled and talented executives. Accordingly, we consider market survey results in establishing target compensation levels for all components of compensation. The market survey information is provided to us every other year by our compensation consultant. In years in which our consultant does not provide us with market survey information, our process is to apply an aging factor to the prior year’s information with assistance from our consultant, based on its experience in the marketplace. Compensation decisions for 2008 were based on a compensation survey performed in 2007. The 2007 survey information was used to set 2009 compensation. Prior to the consultant’s conducting the biennial market study, we assist our consultant in matching our positions with benchmark positions in its database by comparing the specific responsibilities of our positions with the benchmark duties. If we are unable to find an exact match for one of our positions in the consultant’s database due to variances in duties and or position level, we and our consultant agree on the most similar position. The market survey information may then be adjusted upward or downward as necessary to match our position as closely as possible.

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

The companies included in the market surveys are a group of utilities and general industry companies of various sizes in terms of revenue. Approximately half of the companies included in the most recent market surveys had substantially the same levels of annual revenues as SCANA had, while the remainder had revenues ranging from one-seventh to not greater than 3.6 times SCANA's revenues. Market survey results for each position are size-adjusted using regression analysis to account for these differences in company revenues, which in turn are viewed as a proxy for measuring the relative scope and complexity of the business operations. The vast majority of the companies included in the survey were those who participate in our compensation consultant’s database; data for the remaining companies was obtained via proxy disclosures.

The companies included in the market survey we used in connection with setting base salaries and short- and long-term incentive compensation for 2008, and the states in which they are headquartered are listed below:

Utility Industry: AGL Resources, Inc. (GA); Allegheny Energy, Inc. (PA); Allete, Inc. (MN); Ameren Corporation (MO); Aquila, Inc. (MO); Black Hills Corporation (SD); CenterPoint Energy (TX); Cleco Corporation (LA); CMS Energy Corporation (MI); Dominion Resources, Inc. (VA); DTE Energy Company (MI); Duke Energy Corporation (NC); Dynegy, Inc. (TX); Edison International (CA); El Paso Electric Company (TX); FPL Group, Inc. (FL); NiSource Inc. (IN); Pepco Holdings, Inc. (DC); Portland General Electric Co. (OR); PPL Corporation (PA); Progress Energy, Inc. (NC); Public Service Enterprise Group (NJ); Sempra Energy (CA); Southern Company (GA); WGL Holdings, Inc. (DC).

General Industry: Alliant Techsystems Inc. (MN); ALLTEL Corporation (AR); Armstrong World Industries (PA); Avaya (NJ); Avery Dennison Corp. (CA); Ball Corporation (CO); BorgWarner Inc. (MI); The Clorox Company (CA); Cameron International Corp. (TX); Cooper Industries (TX); Ecolab Inc. (MN); El Paso Corporation (TX); FMC Corporation (PA); Hasbro, Inc. (RI); The Hershey Company (PA); MeadWestvaco Corporation (VA); Packaging Corp. of America (IL); Praxair, Inc. (CT); Rockwell Collins, Inc. (IA); The Sherwin-Williams Co. (OH); Sonoco Products Company (SC); Steelcase Inc. (MI); Wm. Wrigley Jr. Company (IL).

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

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

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

Personal Qualifications

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

Mr. Timmerman has been our Chief Executive Officer for 12 years, and has been employed with us in various capacities, including Chief Financial Officer, for 30 years. Mr. Timmerman started his career as a certified public accountant. As our Chief Executive Officer, Mr. Timmerman has responsibility for strategic planning, development of our senior executive officers and oversight of all our operations.

Mr. Addison was appointed our Senior Vice President and Chief Financial Officer in April 2006, prior to which time he had served as our Vice President — Finance since 2001. As Chief Financial Officer, he is responsible for all of our financial operations, including accounting, risk management, treasury, regulatory affairs, investor relations, shareholder services, taxation and financial planning, as well as our information technology functions. Mr. Addison is a certified public accountant, and has been with us for 17 years.

Mr. Marsh is Senior Vice President of SCANA and was appointed our President and Chief Operating Officer in April 2006, prior to which time he had served as SCANA’s Senior Vice President and Chief Financial Officer since 1998. As President of SCE&G, he is responsible for all of its gas and electric operations, as well as for all of our facilities and properties management. Mr. Marsh previously practiced as a certified public accountant, and has been with us for 24 years.

Mr. Byrne is Senior Vice President-Generation, Nuclear and Fossil Hydro. In these positions, he is responsible for overseeing all of our activities related to nuclear power, including nuclear plant operations, emergency planning, licensing and nuclear support services. He has been with us for 13 years, and has over 22 years experience in the nuclear industry.

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

Other Factors Considered

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

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

In 2008, the Human Resources Committee reviewed summaries of compensation components (“tally sheets”) for all of our senior executive officers, including the Named Executive Officers. These tally sheets reflected changes in compensation from the prior year and affixed dollar amounts to each component of compensation. Although the Committee did not make any adjustments to executive compensation in 2008 based solely on its review of the tally sheets, it intends to continue to use such tally sheets in the future to review each component of the total compensation package, including base salaries, short- and long-term incentives, severance plans, insurance, retirement and other benefits, as a factor in determining the total compensation package for each senior executive officer. Adjustments to compensation were, however, made based on the factors discussed below.

Timing of Senior Executive Officer Compensation Decisions

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

Base Salaries

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

All Named Executive Officers received base salary increases in February 2008. The Human Resources Committee determined that the increases to base salaries were necessary and appropriate in light of market survey data and individual performance. In making the decisions with respect to the increases in base salaries for each of the Named Executive Officers, the Committee took into consideration recommendations of our Chief Executive Officer.

Short-Term and Long-Term Incentive Compensation

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

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

Short-Term Annual Incentive Plan

Our Short-Term Annual Incentive Plan provides financial incentives for performance in the form of opportunities for annual incentive cash payments. Participants in the Short-Term Annual Incentive Plan include not only our senior executive officers, but also approximately 208 additional employees, including other officers, senior management, division heads and other professionals whose positions or levels of responsibility make their participation in the plan appropriate. Our Chief Executive Officer recommends, and the Human Resources Committee approves, the performance measures, operational goals and other terms and conditions of incentive awards for senior executives, including the Named Executive Officers.

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

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The plan allows for an increase or decrease in short-term incentive award payout of up to 20% of the target award based on an individual’s performance in meeting individual financial and strategic objectives. The plan also allows for an increase or decrease in award payout of up to 50% of the target award. However, cumulative adjustments to target award payouts for all participants may not increase or decrease overall award levels by more than 50%. Individual awards may nonetheless be decreased or eliminated if the Human Resources Committee determines that actual results warrant a lower payout.

For Mr. Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis on the following financial and business objectives for 2008:

·	SCANA achieving earnings per share targets set to reflect published earnings per share guidance; and

·	Performance of our senior executive officers.

For each of our other Named Executive Officers, the Short-Term Annual Incentive Plan placed equal emphasis on the following financial and business objectives for 2008:

·	SCANA achieving earnings per share targets set to reflect published earnings per share guidance; and

·	Our achieving annual business objectives relating to one or more of the following four critical success factors: cost effective operations, profitable growth, excellence in customer service, and developing our people.

The estimated possible payouts that could have been earned under the 2008 awards if performance objectives were met at threshold, target and maximum levels are set forth in the 2008 Grants of Plan-Based Awards Table.

The extent to which each Named Executive Officer’s individual strategic objectives depended upon our achieving one or more of our critical success factors was weighted according to the extent to which the executive was responsible for results of the objectives. The weightings assigned to the business objectives for each Named Executive Officer for 2008 are shown in the table below:

2008 Weightings Assigned to Each Business Performance Objective

for Named Executive Officers

Objective	Mr. Timmerman	Mr. Addison	Mr. Marsh	Mr. Byrne	Mr. Mood
Financial Results	50%	50%	50%	50%	50%
Senior Staff Performance	50%
Cost Effective Operations			10%	30%	47.5%
Profitable Growth		50%
Customer Service			30%	10%	2.5%
Developing our People			10%	10%

SCANA’s earnings per share target for 2008 was $2.97, and SCANA earned $2.95. Accordingly, we did not make any payouts on the earnings per share component of the Short-Term Annual Incentive Plan. However, we achieved our business objectives and our senior executive officers achieved their individual strategic objectives. Accordingly, we made payouts to our senior executive officers, including our Named Executive Officers, with respect to the business and individual strategic objectives portions of the plan. As further discussed below under the caption “ — Discretionary Bonus Award,” we also made a 20% discretionary bonus award to each of our senior executive officers, including our Named Executive Officers, as permitted by the plan. The 2008 Short-Term Annual Incentive Plan payouts based on our achieving our business objectives and our Named Executive Officers’ achieving their individual objectives are reflected in the Summary Compensation Table under the column “Non-Equity Incentive Plan Compensation,” and the discretionary bonuses under the plan are reflected in the Summary Compensation Table under the column “Bonus.”

Individual Strategic Objectives on which 2008 Short-Term Annual Incentive Awards were Based

Our four critical success factors — cost effective operations, profitable growth, excellence in customer service, and developing our people — included the following components, which were included in business unit objectives: implementing workforce planning initiatives; effectively addressing new regulatory, legislative, and environmental requirements and anticipating future needs; focusing on safety and employee wellness; ensuring the security of our people, assets and operations; maintaining focus on cost control and business efficiency; implementing generation expansion plans to meet future growth requirements; pursuing energy efficiency and demand side management initiatives that are cost effective and assist our customers in controlling their energy costs; developing comprehensive facility plans that address long-term needs for transmission, distribution and customer service locations; and focusing on excellence in customer service, including providing reliable service at reasonable rates.

The individual strategic objectives the Human Resources Committee considered with respect to one or more of our critical success factors in determining short-term incentive awards for the Named Executive Officers were as follows:

Mr. Timmerman’s award was based on his contributions and his leadership of other senior executives in achieving our overall corporate strategic plan objectives.

Mr. Addison’s award was based on his successful efforts toward increasing the visibility of SCANA in the financial community; monitoring ever changing and adverse financial markets and obtaining external financing or refinancing on favorable terms; maintaining financial reporting compliance processes and procedures that meet the requirements of the Sarbanes-Oxley Act; and leadership-level participation in regulatory decisions and strategy for 2008.

Mr. Marsh’s award was based on his progress toward creating a customer service task force to review current customer service systems and programs and identify new initiatives; development and implementation of a program to monitor spending and timing of significant capital projects; achievement of a lower accident frequency rate at the Company; completion of the Company’s generation capacity plans; leadership-level participation in regulatory decisions and strategy; and oversight of our implementation of North American Electric Reliability Council and Electric Reliability Organization reliability standards.

Mr. Byrne’s award was based on his reduction of the accident frequency rates at various generation facilities; completion of a selective catalytic reduction project at one of our generation facilities; timely submission of a Combined Operating License Application for our planned new nuclear facility; and implementation of a self-assessment review program at our VC Summer Nuclear Plant.

Mr. Mood’s award was based on the development and provision of additional training to company employees on regulatory and environmental matters to ensure compliance and appropriate reporting of potential concerns; ensuring we have internal expertise in legal, regulatory, environmental and corporate governance departments; and his leadership level participation in regulatory, legal and environmental decisions and strategies to ensure cost effective operations and excellence in customer service.

Discretionary Bonus Award

Our Chief Executive Officer also recommended to the Human Resources Committee a 20% of target discretionary bonus award for our senior executive officers, as well as other eligible participants in the Plan, and both the Human Resources Committee and the Board approved the discretionary payout. The discretionary bonus award was based on the following important accomplishments by our Company:

·	Executing an industry leading contract for construction of new nuclear generation facilities and the related regulatory filings at the state and federal level;

·	Obtaining approval from the Public Service Commission of South Carolina for siting and construction of the nuclear plants under the Base Load Review Act;

·	Having three coal fired generation facilities listed among the twenty most efficient in the United States;

·	Having the V. C. Summer Nuclear Plant ranked by an independent rating agency as third in the nation in capacity factor achieved;

·	Responding early in 2008 to the emerging liquidity crisis and economic decline, and maintaining financial integrity and results of operations in 2008;

·	Prudent management of costs in a difficult economy to ensure earnings guidance was achieved while still maintaining safe and reliable operations;

·	Having retail gas operations in South Carolina score well in our region, and nationally, in the J. D. Power Customer Satisfaction Report;

·	Having SCANA’s common stock decline only 16% compared with a decline of 26% for our peer group, and a decline of 34% for the Dow Jones Industrial Average;

·	Being included in the S&P 500 Index; and

·	Having our long-term credit ratings reaffirmed in 2008.

We believe this discretionary bonus award is well justified and necessary to reward our senior executive officers for their contributions to our success, and to help facilitate retention of our critical human resources.

Long-Term Equity Compensation Plan

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

A portion of each senior executive officer’s potential compensation consists of awards under SCANA’s Long-Term Equity Compensation Plan. The types of long-term equity-based compensation the Human Resources Committee may award under the Plan include incentive and nonqualified stock options, stock appreciation rights (either alone or in tandem with a related stock option), restricted stock, restricted stock units, performance units and performance shares. In recent years, the only long-term equity-based awards have been in the form of performance shares and restricted stock. These long-term equity-based awards are granted subject to satisfaction of specific performance goals and vesting schedules. For the 2008-2010 performance period, awards under the Long-Term Equity Compensation Plan consisted of performance shares and restricted SCANA common stock. We have not awarded stock options since 2002 and have no plans to do so in the foreseeable future.

We believe awards of performance shares align the interests of our executives with those of shareholders because the value of such awards is tied to our achieving financial and business goals that would be expected to affect the value of SCANA’s common stock. We believe awards of restricted stock align the interests of our executives with those of shareholders in that they ensure a long-term view of success and they aid in retention of executives.

Performance Share Awards

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

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

Components of 2006-2008 Performance Share Awards

For the 2006-2008 performance cycle, components on which performance share awards to senior executive officers under the Long-Term Equity Compensation Plan were based were as follows: (1) SCANA’s TSR relative to the TSR of a group of peer companies over the three-year period, and (2) a three-year average growth in earnings component based on SCANA’s earnings per share (“EPS”) under generally accepted accounting principles, with adjustments to be made to account for the cumulative effects of any mandated changes in accounting principles and the effects of sales of certain investments or impairment charges related to certain investments (we refer to this component as growth in “EPS from ongoing operations”). TSR over the performance period is equal to the change in SCANA’s common stock price, plus cash dividends paid on SCANA common stock during the period, divided by the common stock price as of the beginning of the period. Sixty percent of 2006-2008 target performance shares were based on the TSR component and 40% were based on the EPS growth component. The allocation of 60% of awards to three-year TSR and 40% to growth in EPS from ongoing operations was made to weight the external performance measure slightly higher than the internal performance measure.

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Performance Criteria for Performance Share Awards Granted in 2006 for the 2006-2008 Performance Period with Payouts Due in 2009

Payouts for performance share awards granted in 2006 for the 2006-2008 performance period were based on SCANA achieving: (1) TSR at or above the 33rd percentile of the Long-Term Equity Compensation Plan peer group over the three-year period, and (2) three-year average growth in EPS from ongoing operations of at least 1.7%.

With respect to the TSR component, executives would earn threshold payouts (equal to 50% of target award) if SCANA ranked at the 33rd percentile in relation to the peer group’s three-year TSR performance. Target payouts (equal to 100% of target award) would be earned if SCANA ranked at the 50th percentile in relation to the peer group’s three-year TSR performance. Maximum payouts (equal to 150% of target award) would be earned if SCANA ranked at or above the 75th percentile in relation to the peer group’s three-year TSR performance. Payouts were scaled between 50% and 150% based on the actual percentile achieved. No payouts would be earned if TSR performance was less than the 33rd percentile and no payouts would exceed 150% of the target award.

The peer group of utilities with which we compared SCANA’s TSR for the 2006-2008 performance period are set forth below:

Allegheny Energy, Inc.; Allete Inc.; Alliant Energy Corporation; Ameren Corporation; Avista Corporation; Cleco Corporation; CMS Energy Corporation; Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources, Inc.; DPL, Inc.; DTE Energy Company; Edison International; Entergy Corporation; FirstEnergy Corp.; FPL Group, Inc.; Great Plains Energy, Inc.; Hawaiian Electric Industries, Inc.; IDACORP, Inc.; Integrys Energy Group, Inc.; NiSource Inc.; Northeast Utilities; NorthWestern Corporation; NSTAR; NV Energy, Inc. (f/k/a Sierra Pacific Resources); OGE Energy Corp.; Pepco Holdings, Inc.; Pinnacle West Capital Corporation; PNM Resources, Inc.; PPL Corporation; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; Puget Energy, Inc.; Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UniSource Energy Corporation; Vectren Corporation; Westar Energy, Inc; Wisconsin Energy Corporation

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

For the three-year performance period 2006-2008, SCANA’s TSR was at the 51st percentile of the peer group’s TSR, which resulted in a 102% payout on the TSR component of the awards.

With respect to the EPS component of the 2006-2008 awards, executives would earn threshold payouts (equal to 50% of target award) at 1.7% average growth, target payouts (equal to 100% of target award) at 3.7% average growth and maximum payouts (equal to 150% of target award) at or above 5.7% average growth. Payouts were scaled between 50% and 150% based on the actual growth in EPS from ongoing operations achieved. No payouts would occur if average growth in EPS from ongoing operations over the period was less than 1.7% and no payouts would exceed 150% of target award. These threshold, target and maximum payout levels were consistent with the earnings growth guidance provided publicly by management at the time of the grants.

For the three-year performance period 2006-2008, SCANA’s average growth in EPS from ongoing operations was 2.2%, resulting in a payout of 62.5 % of the EPS component of the awards.

The overall payout of 86.2% of the target shares, which occurred in March, 2009, is reflected in the 2008 Option Exercises and Stock Vested Table.

Performance Share Awards Granted in 2007 for the 2007-2009 Performance Period with Payouts Due, if at all, in 2010

In 2007, we granted performance share awards to each of the Named Executive Officers. As further discussed below, the design of performance share awards under the Long-Term Equity Compensation Plan for the 2007-2009 period was modified from the design of the 2006-2008 performance share awards. We implemented these changes for the 2007-2009 period because we believed that they would increase the effectiveness of the Plan in encouraging executive retention by minimizing the impact of extraordinarily strong or poor single-year performance on award payouts, while generally requiring that the executives continue employment with us for the entire three-year period to receive a payout.

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For the 2007-2009 period, components on which we based performance share awards to senior executive officers were as follows: (1) SCANA TSR relative to the TSR of a peer group of companies, and (2) an average growth in earnings component based on growth in SCANA's “GAAP-adjusted net earnings per share from operations” as that term is used in SCANA’s periodic reports and external communications. (For an explanation of GAAP-adjusted net earnings per share from operations, see the discussion of Results of Operations in ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in Part II above.) GAAP-adjusted net earnings per share from operations may reflect different or additional adjustments than are or would have been reflected in the determination of EPS from ongoing operations in prior plan cycles. As in prior periods, SCANA's TSR over the performance period is equal to the change in SCANA’s common stock price, plus cash dividends paid on SCANA’s common stock during the period, divided by the common stock price as of the beginning of the period. Sixty percent of target performance shares are based on the TSR component, and 40% are based on the growth in earnings component. As in 2006, this allocation was made to weight the external performance measure slighter higher than the internal performance measure.

Performance measurement and award determination for the 2007-2009 period is made on an annual basis (rather than the above described three-year measurement and determination used for 2006-2008 awards), with payment of awards being deferred until after the end of the three-year period. Accordingly, payouts under the 2007-2009 three-year period will be earned for each year that performance goals are met during the three-year period, but payments will be deferred until the end of the three-year period and will be contingent upon the participant’s still being employed with us at the end of the three-year period, subject to certain exceptions in the event of retirement, death or disability. Payouts would be accelerated in the event of certain change in control events. See “— Potential Payments Upon Termination or Change in Control.” The other performance criteria adopted by the Board on recommendation of the Human Resources Committee for the 2007-2009 period do not differ materially from 2006-2008 performance cycle.

Performance Criteria for the 2007-2009 Performance Share Awards and Earned Awards for the 2008 Performance Period

Payouts based on the TSR component of the 2007-2009 plan are scaled according to SCANA’s ranking against the peer group. Executives earn threshold payouts (equal to 50% of target award) for each year of the three-year period in which SCANA ranks at the 33rd percentile in relation to the peer group’s TSR performance for the one-year period. Target payouts (equal to 100% of target award) are earned for each year of the three-year period in which SCANA ranks at the 50th percentile in relation to the peer group’s TSR performance for the one-year period. Maximum payouts (equal to 150% of target award) are earned for each year of the three-year period in which SCANA’s performance ranks at or above the 75th percentile in relation to the peer group’s TSR performance for the one-year period. Payouts are scaled between 50% and 150% based on the actual percentile achieved. No payout is earned if SCANA's performance is less than the 33rd percentile, and no payouts may exceed 150% of the target award. Threshold, target and maximum payouts at the 33rd, 50th and 75th percentiles were used because these generally matched the levels used by the companies in the market survey data.

The peer group of utilities with which we compared SCANA’s TSR for the 2007-2009 period are set forth below:

Allegheny Energy, Inc.; Alliant Energy Corporation; Ameren Corporation; American Electric Power; Avista Corporation; Centerpoint Energy Inc.; CMS Energy Corporation; Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources, Inc.; DPL, Inc.; DTE Energy Company; Duke Energy Corporation; Edison International; Entergy Corporation; Exelon Corporation; FirstEnergy Corp.; FPL Group, Inc.; Great Plains Energy, Inc.; Hawaiian Electric Industries, Inc.; Integrys Energy Group, Inc.; NiSource Inc.; Northeast Utilities; NorthWestern Corporation; NSTAR; NV Energy, Inc. (f/k/a Sierra Pacific Resources); OGE Energy Corp.; Pepco Holdings, Inc.; PG&E Corporation; Pinnacle West Capital Corporation; PNM Resources, Inc.; PPL Corporation; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; Puget Energy, Inc.; Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UniSource Energy Corporation; Vectren Corporation; Westar Energy, Inc.; Wisconsin Energy Corporation; XCEL Energy, Inc.

For the reasons discussed above under “—Performance Share Awards Granted in 2006 for the 2006-2008 Performance Period with Payouts due in 2009,” the number of utilities in the peer group above is larger than the number included in the market survey utility peer group we use for setting base salary and short and long-term compensation.

For the first and second years of the 2007-2009 period, SCANA’s TSR was at the 59th and 82nd percentiles, respectively, which resulted in awards on the TSR component being earned at 118% and 150% for the respective years, payment of which will be deferred until the end of the three-year period as discussed above. See the “Outstanding Equity Awards at 2008 Fiscal Year-End” Table.

With respect to the growth in earnings component for the 2007-2009 period, executives earn threshold payouts (equal to 50% of target award) for each year in the three-year period in which growth in SCANA’s GAAP-adjusted net earnings per share from operations equals 2%. Executives earn target payouts (equal to 100% of target award) for each year in which such growth equals 4%, and maximum payouts (equal to 150% of target award) for each year in which such growth equals or exceeds 6%. Payouts are scaled between 50% and 150% based on the actual growth in SCANA’s GAAP-adjusted net earnings per share from operations achieved. No payouts will be earned for any year in which growth in SCANA’s GAAP-adjusted net earnings per share from operations is less than 2%, and no payouts will exceed 150% of target award.

For the first and second years of the 2007-2009 period, SCANA’s growth in GAAP-adjusted net earnings per share from operations were 5.8% and 7.7%, respectively, which resulted in awards for this component being earned at 145% and 150% for the respective years. As discussed above, payment of these awards will be deferred until the end of the three-year period. See the “Outstanding Equity Awards at 2008 Fiscal Year-End” table.

2008-2010 Performance Share and Restricted Stock Awards

On the recommendation of the Human Resources Committee, our Board approved further changes to the design of awards for the 2008-2010 period to reflect the evolving business climate within which we operate. As discussed above, each of the grants for the 2006-2008 and 2007-2009 performance cycles under SCANA’s Long-Term Equity Compensation Plan provided for awards of performance shares, 60% of which would be earned based on SCANA’s level of success in achieving certain TSR targets as compared to the TSR of a peer group of companies, and 40% of which would be earned based on SCANA’s level of success in achieving certain EPS growth targets. The performance share awards for the 2006-2008 period provided for a three-year measurement period, and the performance share awards for the 2007-2009 period provided for annual measurement periods.

The Human Resources Committee considered the fact that the performance thresholds were not met with respect to either the SCANA TSR or EPS growth components for the 2004-2006 cycle, nor was the performance threshold met with respect to the SCANA TSR component for the 2005-2007 cycle. Although threshold performance was met with respect to the SCANA EPS growth component for the 2005-2007 cycle, performance shares earned and paid out were only 57.5% of the targeted 40% award, resulting in an overall payout of 23%.

When the Committee adopted the criteria for awards for the 2008-2010 period, it appeared that the performance threshold with respect to the SCANA TSR component for the 2006-2008 cycle would not be met, and that the performance threshold for the SCANA EPS component would only be met between threshold and target. The Committee based its decision to change the criteria for the 2008-2010 cycle on its belief that the below threshold performance described above, and what it anticipated would be below threshold to marginal performance for the 2006-2008 cycle, indicated that criteria were unrealistic. Although thresholds for the 2006-2008 cycle were ultimately exceeded for both the SCANA TSR and EPS component, it was not possible to predict early in the year that the economic downturn would impact our peers negatively and that SCANA’s long-term equity cycles would end the year with a positive accrual.

In February 2008, we believed the principal reason for the below threshold performance in prior years with respect to the SCANA TSR component of the awards was that our announced plans to build new generation capacity, including our consideration of a potential new nuclear facility, have depressed the market price of SCANA stock. We believe the construction of new generation capacity is in our long-term best interests, and the long-term best interests of SCANA’s shareholders and the communities we serve, but it appears to us that the financial markets may have a more short-term focus. Although alignment of our executives’ interests with shareholder interests is very important, we wish to continue to encourage our executives and our employees to focus on our long-term goals and avoid having their strategic decisions driven by short-term market performance. Accordingly, to reduce the potential negative impact that might result from our plans for increased generation capacity, we made further adjustments to the design of the awards under the Long Term Equity Compensation Plan.

Because we believed our plans to build new generation capacity were a primary reason for SCANA’s depressed stock price and resulting failure to meet its TSR targets, we asked our compensation consultant to review the long-term incentive practices of a group of peer utility companies that have announced an interest in expanding generation capacity, including those considering building new nuclear facilities. The companies included in this modified 2008 survey are as follows:

AES; Ameren; American Electric Power; CenterPoint Energy; Consolidated Edison; Constellation; Dominion; DTE Energy; Duke Energy; Edison International; Entergy; Exelon; FirstEnergy; FPL Group; Integrys Energy Group; Nisource; NRG Energy; Pepco Holdings; PG&E; PPL; Progress Energy; Public Service Enterprise Group; Reliant Energy; Southern Company; Xcel Energy.

Among other findings, the survey revealed the following:

·	Type of program. Although 96% of these utilities use performance plans, over 80% of them also grant restricted stock or stock options. Only four of the companies (16%) use only performance plans for their long-term incentive grants.

Performance leverage. The survey also indicated that most of these companies have wider performance ranges than SCANA does. SCANA’s TSR performance range was from the 33rd percentile to the 75th percentile; however, the peer group comparison denoted a performance range from the 28th percentile to the 83rd percentile.

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Payout leverage. Additionally, the survey indicated that some of these companies have lower minimum payouts and higher maximum payouts than we do. Whereas we pay out 50% of target award at threshold performance (33%), the median threshold payout by the peer group is 25% of target, and our maximum payout is 150% of target as compared to maximum median payout by the peer group of 200% of target.

Based on this review, the Committee approved changes to the 2008-2010 long-term incentive awards to address certain disparities between our program design and those of the peer companies. The approved changes modified the performance and payout ranges for the 2008-2010 awards, equally weighted the external and internal performance measures, and added a restricted stock grant which was not performance based.

Instead of awards being denominated solely in performance shares which are based 60% on our level of achieving SCANA TSR targets and 40% on our level of achieving SCANA EPS growth targets, awards for the 2008-2010 period are comprised of a combination of performance shares and restricted stock. Performance shares represent 80% of the awards, consisting of one half to be earned based on our level of achieving SCANA TSR targets and the remaining one half to be earned based on our level of achieving SCANA EPS growth targets. The remaining 20% of the awards will be in the form of restricted stock. The restricted stock will vest at the end of the three year performance period, if at all, and will not be performance based. Although restricted stock does not have the same risk of forfeiture for failure to meet performance thresholds associated with performance shares, it has no upside potential for payout above target level.

Components of 2008-2010 Performance Share Awards

In 2008, we granted performance share awards to each of the Named Executive Officers. Information about the components of the awards and the performance criteria for the 2008 three-year period is set forth below. Information about the number of performance shares that could be earned at threshold, target and maximum performance levels for the 2008 three-year period is provided in the “2008 Grants of Plan-Based Awards” table.

As was the case for the 2007-2009 period, components on which we based performance share awards to senior executive officers were (1) SCANA’s TSR relative to the TSR of a peer group of companies and (2) an average growth in earnings component based on growth in SCANA's “GAAP-adjusted net earnings per share from operations” as that term is used in SCANA’s periodic reports and external communications. As noted above, GAAP-adjusted net earnings per share from operations may reflect different or additional adjustments than are, or would have been, reflected in the determination of EPS from ongoing operations in prior plan cycles. As in prior periods, TSR over the performance period is equal to the change in SCANA’s common stock price, plus cash dividends paid on SCANA common stock during the period, divided by the common stock price as of the beginning of the period. Half of target performance shares are based on each of the two components. This allocation was made to weight the performance measures equally and to allow for a time-based restricted stock award.

Performance Criteria for the 2008-2010 Performance Share Awards and Earned Awards for the 2008 Performance Period

Performance measurement and award determination for the 2008-2010 cycle will also be made on an annual basis with payment of awards being deferred until after the end of the three-year period. Accordingly, payouts under the 2008-2010 three-year period will be earned for each year that performance goals are met during the three-year period, but payments will be deferred until the end of the period and will be contingent upon the participants still being employed by us at the end of the period, subject to certain exceptions in the event of retirement, death or disability.

Payouts based on the TSR component of the 2008-2010 plan are scaled according to SCANA's ranking against the peer group. Executives earn threshold payouts (equal to 25% of target award) for each year of the three-year period in which SCANA ranks at the 25th percentile in relation to the peer group’s TSR performance for the one-year period. Target payouts (equal to 100% of target award) are earned for each year of the three-year period in which SCANA ranks at the 50th percentile in relation to the peer group’s TSR performance for the one-year period. Maximum payouts (equal to 175% of target award) are earned for each year of the three-year period in which SCANA’s performance ranks at or above the 90th percentile in relation to the peer group’s TSR performance for the one-year period. Payouts are scaled between 25% and 175% based on the actual percentile achieved. No payout is earned is our performance is less than the 25th percentile, and no payouts may exceed 175% of the target award. Threshold, target and maximum payouts at the 25th, 50th and 90th percentiles were used because these generally match the levels used by the companies in the market survey data.

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The peer group of utilities with which we compared SCANA’s TSR for the 2008-2010 period are set forth below:

For the reasons discussed above under “Performance Share Awards Granted in 2006 for the 2006-2008 Performance Period with Payouts Due in 2009,” the number of utilities included in the peer group used for TSR comparisons is larger than the number included in the market survey utility peer group we use for purposes of setting base salary and short- and long-term incentive compensation.

For the first year of the 2008-2010 period, SCANA’s TSR was at the 82nd percentile, which resulted in an award on the TSR component being earned at 160%, payment of which will be deferred until the end of the three-year period as discussed above. See the “Outstanding Equity Awards at 2008 Fiscal Year-End” table.

With respect to the growth in earnings component for the 2008-2010 period, executives earn threshold payouts (equal to 25% of target award) for each year in the three-year period in which growth in SCANA’s GAAP-adjusted net earnings per share from operations equals 1%. Executives earn target payouts (equal to 100% of target award) for each year in which such growth equals 4%, and maximum payouts (equal to 175% of target award) for each year in which such growth equals or exceeds 7%. Payouts are scaled between 25% and 175% based on the actual growth in SCANA’s GAAP-adjusted net earnings per share from operations. No payouts will be earned for any year in which growth in SCANA’s GAAP-adjusted net earnings per share from operations is less than 1%, and no payouts will exceed 175% of target award.

For the first year of the 2008-2010 period, growth in SCANA’s GAAP-adjusted net earnings per share from operations was 7.7%, which resulted in awards on the earnings per share component being earned at 175%, payment of which will be deferred until the end of the three-year period as discussed above. See the “Outstanding Equity Awards at 2008 Fiscal Year-End” table.

Restricted Stock Component of the 2008-2010 Long-Term Equity Plan Grant

The remaining twenty percent of the 2008-2010 Long Term Equity Compensation Plan award was granted in the form of SCANA restricted stock. The grants were made on February 14, 2008, and were based on fair market value on the date of grant. The restricted stock is subject to a three year vesting period which we believe aids in leadership retention. The restricted stock has voting rights prior to vesting and the restricted stock award is also subject to forfeiture in the event of retirement or termination of employment. As previously mentioned, although restricted stock does not have the same risk of forfeiture for failure to meet performance thresholds associated with performance shares, it has no upside potential for payout above target level.

Information about the restricted stock awards granted for the 2008 three-year period is provided in the “2008 Grants of Plan-Based Awards Table.” See also the “Outstanding Equity Awards at 2008 Fiscal Year-End Table.”

2009 Compensation

At its February 2009 meeting, the Board, on recommendation of the Human Resources Committee, determined that no executive officer, including our Named Executive Officers, would receive a salary increase. In addition, the Board, also on the recommendation of the Human Resources Committee, determined performance awards and criteria for both the Short-Term Incentive Plan and the Long-Term Equity Compensation Plan. Such awards and performance criteria do not differ materially from the 2008 awards.

In 2008, the Human Resources Committee adopted amendments to SCANA’s deferred compensation plans as necessary to address issues raised by Internal Revenue Code Section 409A.

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Retirement and Other Benefit Plans

We currently participate in the following retirement benefit plans sponsored by SCANA (as such, these plans may be referred to herein as “our” plans):

· a tax qualified defined benefit retirement plan (the “Retirement Plan”);

·	a nonqualified defined benefit Supplemental Executive Retirement Plan (the “SERP”) for our senior executive officers;

· a tax qualified defined contribution plan (the “401(k) Plan”); and

·	a nonqualified defined contribution Executive Deferred Compensation Plan (the “EDCP”) for our senior executive officers.

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

The SERP and the EDCP plans are designed to provide a benefit to senior executive officers who participate in the Retirement Plan or 401(k) Plan (our tax qualified retirement plans) and whose participation in those tax qualified plans at the same percentage of salary as all other employees is otherwise limited by government regulation. The SERP and EDCP participants are provided with the benefits to which they would have been entitled under the Retirement Plan or 401(k) Plan had their participation not been limited. At present, certain executive officers, including the Named Executive Officers, are participants in the SERP and /or EDCP. The SERP is described under the caption “Potential Payments Upon Termination or Change in Control — Retirement Benefits — Supplemental Executive Retirement Plan” and the EDCP is described under the caption “2008 Nonqualified Deferred Compensation — Executive Deferred Compensation Plan.” We provide the SERP and EDCP benefits because they allow our senior executive officers the opportunity to defer the same percentage of their compensation as other employees. We also believe, based on market survey data, that these plans are necessary to make our senior executive officer retirement benefits competitive.

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

Termination, Severance and Change in Control Arrangements

We have entered into arrangements with certain of our senior executive officers, including our Named Executive Officers, that provide for payments to them in the event of a change in control of SCANA or SCE&G. These arrangements, including the triggering events for payments and possible payment amounts, are described under the caption “Potential Payments Upon Termination or Change in Control.” We believe that these arrangements are not uncommon for executives at the level of our Named Executive Officers, including executives of the companies included in our compensation market survey information, and are generally expected by those holding such positions. We believe these arrangements are an important factor in attracting and retaining our senior executive officers by assuring them financial and employment status protections in the event control of SCANA or SCE&G changes. We believe such assurances of financial and employment protections help free executives from personal concerns over their futures, and thereby, can help to align their interests more closely with those of shareholders in negotiating transactions that could result in a change in control.

Perquisites

We provide a number of perquisites to senior executive officers as summarized below.

Company Aircraft

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

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For purposes of determining total 2008 compensation, we valued the aggregate incremental cost of the personal use of our aircraft using a method that takes into account the variable expenses associated with operating the aircraft, which variable expenses are only incurred if the planes are flying. The following items are included in our aggregate incremental cost: aircraft fuel and oil expenses per hour of flight; maintenance, parts and external labor (inspections and repairs) per hour of flight; landing/parking/flight planning services expenses; crew travel expenses; and supplies and catering.

Medical Examinations

We provide each of our senior executive officers the opportunity to have a comprehensive annual medical examination from Duke University, the Medical University of South Carolina or the physician of his or her choice. We believe this examination helps encourage health conscious senior executive officers, and helps us plan for any health related retirements or resignations.

Security Systems

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

Other Perquisites

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

Accounting and Tax Treatments of Compensation and Other Compensation Discussion

Deductibility of Executive Compensation

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

Nonqualified Deferred Compensation

On January 1, 2005, the Internal Revenue Code was amended to include a new Section 409A, which would impose interest and penalties on our executives’ receipt of certain types of deferred compensation payments. Deferred compensation plans were required to be amended to comply with the requirements of Section 409A, if necessary, by the end of 2008 to avoid imposition of such interest and penalties. SCANA has made the necessary amendments.

Accounting for Stock Based Compensation

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

Financial Restatement

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

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Security Ownership Guidelines for Executive Officers

We do not currently have any equity or other security ownership requirements for executive officers (specifying applicable amounts and forms of ownership), or any policies regarding hedging the economic risk of such ownership. However, all of our senior executive officers have a significant amount of their 401(k) plan accounts invested in SCANA stock and we are now awarding twenty percent of our long-term equity awards in the form of restricted stock and/or restricted stock units, which have a three year vesting period.

The directors believe that significant at-risk compensation denominated in common stock equivalents creates a meaningful investment in the Company’s stock for each executive, which is the reason we do not have a requirement for executives to own a specified number of shares of SCANA common stock. The following table sets out direct and at-risk stock ownership by executives. Our Chief Executive Officer and the Human Resources Committee consider this direct and at-risk stock ownership when evaluating an executive’s annual performance, to determine whether an executive’s ownership is appropriate considering the executive’s age, tenure and years remaining to retirement.

Senior Staff Member	Title	Age*	Years of Service*	Shares Held D Directly	Deferred Compensation Shares (401(k) & EDCP)	Accrued but not vested Performance Shares for LTEP	Total Shares
W. B. Timmerman	Chief Executive Officer	62	30	41,766	91,137	98,836	231,739
J. E. Addison	Senior Vice President and Chief Financial Officer	48	17	3,224	13,359	16,895	33,478
J. C. Bouknight	Senior Vice President	56	4	2,201	2,840	12,440	17,481
S. D. Burch	Senior Vice President	51	17	1,904	12,098	9,079	23,081
S. A. Byrne	Senior Vice President	49	13	3,826	24,009	21,965	49,800
K. B. Marsh	President and Chief Operating Officer	53	24	11,193	20,754	34,950	66,898
F. P. Mood, Jr.	Senior Vice President and General Counsel	71	4	2,950	1,449	16,794	21,193

*Calculated as of February 16, 2009.

Compensation Committee Report

The Human Resources Committee has reviewed and discussed with management the “Compensation Discussion and Analysis” included herein. Based on that review and discussion, the Human Resources Committee recommended to our Board of Directors that the “Compensation Discussion and Analysis” be included in our Annual Report on Form 10-K for the year ended December 31, 2008 for filing with the Securities and Exchange Commission.

Mr. G. Smedes York (Chairman)

Mr. James A. Bennett

Mrs. Sharon A. Decker

Mr. D. Maybank Hagood

Mr. James M. Micali

Ms. Lynne M. Miller

Mr. James W. Roquemore

Mr. Maceo K. Sloan

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SUMMARY COMPENSATION TABLE

The following table summarizes information about compensation paid or accrued during 2008, 2007 and 2006 to our Chief Executive Officer, our Chief Financial Officer and our three next most highly compensated executive officers during 2008. (As noted in the Compensation Discussion and Analysis, we refer to these persons as our Named Executive Officers.)

Name and Principal Position		Year	Salary ($)	Bonus ($)(1)	Stock Awards ($)(2)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
		2008	$1,094,985	$186,830	$4,614,170	-	$467,075	$334,694	$123,448	$6,821,202
W. B. Timmerman, Chief Executive Officer		2007 2006	$1,043,408 $1,002,700	$177,956 $170,459	$1,761,331 $301,759	- -	$444,890 $426,148	$330,605 $274,724	$121,481 $73,629	$3,879,671 $2,249,419
J. E. Addison, Senior Vice President Chief Financial Officer		2008 2007 2006	$385,048 $303,846 $278,990	$46,891 $36,600 $27,916	$715,936 $252,274 $37,505	- - -	$117,229 $91,500 $69,789	$43,676 $41,300 $21,981	$56,538 $29,242 $30,091	$1,365,318 $754,762 $466,272
K. B. Marsh, President and Chief Operating Officer		2008 2007 2006	$577,692 $548,115 $516,183	$75,400 $71,500 $66,916	$1,630,379 $613,229 $106,749	- - -	$188,500 $178,750 $167,290	$100,108 $113,085 $59,934	$55,229 $53,730 $63,816	$2,627,309 $1,578,409 $980,888
		2008	$443,077	$53,400	$1,022,834	-	$133,500	$56,283	$43,470	$1,752,564
S. A. Byrne, Senior Vice President		2007 2006	$418,492 $400,400	$50,400 $48,048	$375,124 $66,274	- -	$126,000 $120,120	$62,519 $40,226	$42,093 $45,550	$1,074,628 $720,618
F. P. Mood, Jr., Senior Vice President and General Counsel		2008 2007 2006	$388,462 $368,462 $350,000	$42,900 $37,000 $35,000	$779,336 $285,537 $50,033	- - -	$107,250 $92,500 $87,500	$54,276 $49,607 $59,582	$37,836 $37,465 $41,051	$1,410,060 $870,571 $623,166

(1)	Discretionary bonus awards as permitted under the 2008 Short-Term Annual Incentive Plan, which are discussed in further detail under “— Compensation Discussion and Analysis — Short-Term Annual Incentive Plan — Discretionary Bonus Award.”

(2)

The information in this column relates to performance share and restricted stock awards (liability awards) under the Long-Term Equity Compensation Plan. This plan is discussed under “— Compensation Discussion and Analysis — Long-Term Equity Compensation Plan.” The figures for 2008 reflect accruals for all three performance plan cycles which were in operation during that year. The amounts in this column are the dollar amounts recognized for financial statement reporting purposes with respect to the fiscal year in accordance with SFAS 123(R). The assumptions made in valuation of stock awards are set forth in Note 3 to our audited financial statements for the year ended December 31, 2008, which are included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA in Part II above.

The 2006 information in this column also reflects the amounts recognized for financial reporting purposes in accordance with SFAS 123(R). However, amounts reported in this column for 2006 do not reflect the reversal in 2006 of previously expensed portions of awards to the extent those expenses had been recorded in periods prior to 2006. As such, the figures for 2006 reflect only the accrual of costs in 2006 related to the 2006-2008 plan cycle.

(3)

Payouts under the 2008 Short-Term Annual Incentive Plan, based on our achieving our business objectives and our Named Executive Officers’ achieving their individual financial and strategic objectives, as discussed in further detail under “— Compensation Discussion and Analysis — Short-Term Annual Incentive Plan.”

(4)

The aggregate change in the actuarial present value of each Named Executive Officer’s accumulated benefits under SCANA’s Retirement Plan and Supplemental Executive Retirement Plan from December 31, 2007 to December 31, 2008, determined using interest rate and mortality rate assumptions consistent with those used in our financial statements. These plans are discussed under “— Compensation Discussion and Analysis — Retirement and Other Benefit Plans,” “— Defined Benefit Retirement Plan,” “— Supplemental Executive Retirement Plan,” “ — Potential Payments Upon Termination or Change in Control,” “— Potential Payments Upon Termination or Change in Control — Retirement Benefits —Supplemental Executive Retirement Plan.”

(5)

All other compensation paid to each Named Executive Officer, including company contributions to the 401(k) Plan and the Executive Deferred Compensation Plan, tax reimbursements with respect to perquisites or other personal benefits, life insurance premiums on policies owned by Named Executive Officers, and perquisites that exceeded $10,000 in aggregate for any Named Executive Officer. For 2008, the Company contributions to defined contribution plans were as follows: Mr. Timmerman $102,829; Mr. Addison $29,900; Mr. Marsh $49,538; Mr. Byrne $37,053; and Mr. Mood $30,772. For 2008, tax reimbursements with respect to perquisites or other personal benefits were as follows: Mr. Timmerman $128; Mr. Addison $1,607; and Mr. Byrne $388. Perquisites exceeded $10,000 for each of Mr. Timmerman and Mr. Addison. Mr. Timmerman’s All Other Compensation includes perquisites of $11,575 consisting of expenses related to the Company provided medical examination, financial planning services, maintenance and monitoring of residential security systems, and travel expenses associated with his spouse occasionally accompanying him on business travel. Mr. Addison’s All Other Compensation includes perquisites of $15,603 consisting of expenses related to the Company provided medical examination, financial planning services, maintenance and monitoring of residential security systems, and personal travel on the Company plane for medical care. Life insurance premiums on policies owned by the Named Executive Officers did not exceed $10,000 for any Named Executive Officer.

(6)

This column includes not only compensation actually received in 2008, but also accruals for compensation that could be paid in 2010 and 2011 if performance criteria under the 2007-2009 and 2008-2010 performance periods under the Long-Term Equity Compensation Plan are met. Total compensation represented in this column that was actually received by each Named Executive Officer for 2008 (including amounts accrued in earlier years) and compensation accrued for possible payment in future years are as follows: Mr. Timmerman, $4,676,832 ($2,705,147 of the amount in column (e) represents accruals for compensation that may be paid, if at all, in 2010 and 2011); Mr. Addison, $956,345 ($478,670 of the amount in column (e) represents accruals for compensation that may be paid, if at all, in 2010 and 2011); Mr. Marsh, $1,875,657 ($955,052 of the amount in column (e) represents accruals for compensation that may be paid, if at all, in 2010 and 2011); Mr. Byrne, $1,272,157 ($603,567 of the amount in column (e) represents accruals for compensation that may be paid, if at all, in 2010 and 2011); and Mr. Mood, $1,040,230 ($462,809 of the amount in column (e) represents accruals for compensation that may be paid, if at all, in 2010 and 2011).

2008 GRANTS OF PLAN-BASED AWARDS

The following table sets forth information about each grant of an award made to a Named Executive Officer under our compensation plans during 2008.

		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payouts Under Equity Incentive Plan Awards(2)(4)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)	All Other Stock Awards: Number of Shares of Stock or Units (#)(3)(4)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/Sh)	Grant Date Fair Value of Stock and Option Awards ($)(5)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)
W. B. Timmerman	2-14-08 2-14-08 2-14-08	$467,075	$934,150	$1,401,225	16,148	64,590	113,033	17,006	— — —	— — —	4,221,783 635,174
J. E. Addison	2-14-08 2-14-08 2-14-08	$117,229	$234,457	$351,686	3,061	12,244	21,427	3,224	— — —	— — —	800,298 120,416
K. B. Marsh	2-14-08 2-14-08 2-14-08	$188,500	$377,000	$565,500	5,681	22,725	39,769	5,983	— — —	— — —	1,485,372 223,465
S. A. Byrne	2-14-08 2-14-08 2-14-08	$133,500	$267,000	$400,500	3,633	14,530	25,428	3,826	— — —	— — —	949,736 142,901
F. P. Mood, Jr.	2-14-08 2-14-08 2-14-08	$107,250	$214,500	$321,750	2,802	11,206	19,611	2,950	— — —	— — —	732,471 110,183

(1)

The amounts in columns (c), (d) and (e) represent the threshold, target and maximum awards that could have been paid under the 2008 Short-Term Annual Incentive Plan if performance criteria were met. Target awards were based 50% on SCANA achieving its earnings per share objectives and 50% on achieving individual performance objectives. SCANA did not meet the earnings per share objectives, but all of the Named Executive Officers met their individual strategic objectives. Accordingly, there was no payout on the earnings per share component of the award. The amounts shown in column (g) of the Summary Compensation Table, therefore, reflect the threshold payout in column (c) above (50% below target in column (d) above). A discussion of the 2008 Short-Term Annual Incentive Plan is included under “— Compensation Discussion and Analysis — Short-Term Annual Incentive Plan.” See also, “— Compensation Discussion and Analysis — Short-Term Annual Incentive Plan — Discretionary Bonus Award” for a discussion of the discretionary bonus paid under this plan.

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(2)

Represents total potential future payouts of the 2008-2010 performance share awards under the Long-Term Equity Compensation Plan. Payout of performance share awards at the end of the 2008-2010 Plan period will be dictated by SCANA’s performance against pre-determined measures of TSR and growth in GAAP-adjusted net earnings per share from operations for each year of the three-year period. Awards for the 2008 performance period have been earned at 160% of target for the TSR portion and 175% of target for the EPS portion, but will not vest until the end of the 2008-2010 cycle.

(3)	Represents restricted stock awards. Restricted stock awards are time based and vest after three years if the Named Executive Officer is still employed by us at that date, subject to exceptions for death or disability.

(4)

A discussion of the components of the performance share and restricted stock awards is included under “— Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — Components of 2008-2010 Performance Share Awards,” “— Performance Criteria for the 2008-2010 Performance Share Awards and Earned Awards for the 2008 Performance Period” and “— Restricted Stock Component of 2008-2010 Long-Term Equity Plan Grant.”

(5)	The grant date fair value of performance share awards and restricted stock awards computed in accordance with SFAS 123(R). The value for performance share awards is based on the maximum number of shares that could be earned as shown in column (h) above.

OUTSTANDING EQUITY AWARDS AT 2008 FISCAL YEAR-END

The following table sets forth certain information regarding equity incentive plan awards for each Named Executive Officer outstanding as of December 31, 2008.

		Stock Awards
Name	Date of Grant	Number of Shares or Units of Stock That Have Not Vested (#)(1)	Market Value of Shares or Units of Stock That Have Not Vested ($)(2)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(3)(4)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(2)(4)
(a)		(g)	(h)	(i)	(j)
W. B. Timmerman	2-14 -2008 2-14-2008 2-15-2007	36,063 17,006 62,773	$1,283,843 $605,414 $2,234,719	75,356 — 33,774	$2,682,674 — $1,202,354
J. E. Addison	2-14 -2008 2-14-2008 2-15-2007	6,836 3,224 10,059	$243,362 $114,774 $358,100	14,286 — 5,412	$508,582 — $192,667
K. B. Marsh	2-14 -2008 2-14-2008 2-15-2007	12,688 5,983 22,262	$451,693 $212,995 $792,527	26,512 — 11,979	$943,827 — $426,452
S. A. Byrne	2-14 -2008 2-14-2008 2-15-2007	8,112 3,826 13,853	$288,787 $136,206 $493,167	16,954 — 7,452	$603,562 — $265,291
F. P. Mood, Jr.	2-14 -2008 2-14-2008 2-15-2007	6,256 2,950 10,538	$222,714 $105,020 $375,153	13,074 — 5,672	$465,434 — $201,923

(1)

The awards granted on February 14, 2008 represent performance shares and restricted stock awarded under the 2008-2010 performance cycle of the Long-Term Equity Compensation Plan that have been earned, but have not vested. The first year of the 2008-2010 performance cycle awards were earned based on achieving SCANA TSR at the 82nd percentile and growth in SCANA GAAP-adjusted net earnings per share from operations of 7.7%, and such shares will vest on December 31, 2010 if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death or disability. The restricted stock award will vest on December 31, 2010, if the Named Executive Officer is still employed by us at that date, subject to exceptions for death or disability. The awards granted on February 15, 2007 represent performance shares awarded under the 2007-2009 performance cycle of the Long-Term Equity Compensation Plan that were earned for the first two years of the cycle based on achieving SCANA TSR at the 59th and 82nd percentiles respectively, and growth in SCANA GAAP-adjusted net earnings per share from operations of 5.8% and 7.7% respectively, and such shares will vest on December 31, 2009 if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death or disability.

(2)	The market value of these awards is based on the closing market price of SCANA common stock on the New York Stock Exchange on December 31, 2008 of $35.60.

(3)

The awards granted on February 14, 2008 represent performance shares and restricted stock awards remaining in the 2008-2010 performance cycle that have not been earned, and the awards granted February 15, 2007 represent performance shares remaining in the 2007-2009 performance cycle that have not been earned. Assuming the performance criteria are met and the reported payout levels are sustained, the vesting dates of these awards would be as follows: Mr. Timmerman, 96,547 shares would vest on December 31, 2009 and 128,425 shares would vest on December 31, 2010; Mr. Addison, 15,471 shares would vest on December 31, 2009 and 24,346 shares would vest on December 31, 2010; Mr. Marsh, 34,241 shares would vest on December 31, 2009 and 45,183 shares would vest on December 31, 2010; Mr. Byrne, 21,305 shares would vest on December 31, 2009 and 28,892 shares would vest on December 31, 2010; and Mr. Mood, 16,210 shares would vest on December 31, 2009 and 22,280 shares would vest on December 31, 2010.

(4)

For the 2009 period remaining in the 2007-2009 awards, performance shares tracking against SCANA TSR (60% of target shares) are projected to result in a maximum payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the maximum performance measure for the 2009 TSR portion of the shares. Performance shares tracking against growth in SCANA GAAP-adjusted net earnings per share from operations (40% of target shares) for the 2009 period remaining in the 2007-2009 awards are also projected to result in a maximum payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the maximum performance measure for the growth in SCANA's 2009 GAAP-adjusted net earnings per share from operations portion of the shares.

For each of the 2009 and 2010 periods remaining in the 2008-2010 awards, performance shares tracking against SCANA TSR (50% of target shares) are projected to result in between target and maximum payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the maximum performance measure for these 2009 and 2010 TSR portions of the shares. Performance shares tracking against growth in SCANA GAAP-adjusted net earnings per share from operations (50% of target shares) for the 2009 and 2010 periods remaining in the 2008-2010 awards are projected to result in a maximum payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the maximum performance measure for SCANA’s growth in these 2009 and 2010 GAAP-adjusted net earnings per share from operations portions of the shares.

2008 OPTION EXERCISES AND STOCK VESTED

The following table sets forth information about exercises of stock options and stock awards that vested for each Named Executive Officer during 2008. No options were exercised during 2008.

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)(1)	Value Realized on Vesting ($)(1)
(a)	(b)	(c)	(d)	(e)
W. B. Timmerman	—	—	60,416	$2,150,810
J. E. Addison	—	—	7,509	$267,320
K. B. Marsh	—	—	21,373	$760,879
S. A. Byrne	—	—	13,269	$472,376
F. P. Mood, Jr.	—	—	10,017	$356,605

(1)

Represents the portion of the 2006-2008 Performance Share Awards that vested based on SCANA achieving the earnings per share component between threshold and target and the TSR component at slightly above target. Dollar amounts in column (e) are calculated by multiplying the number of shares shown in column (d) by the closing price of SCANA common stock on the vesting date. In addition to the amounts above, each Named Executive Officer also received dividends on the shares listed above. These awards were paid in cash.

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PENSION BENEFITS

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

Name	Plan Name	Number of Years Credited Service (#)(1)	Present Value of Accumulated Benefit ($)(1)(2)	Payments During Last Fiscal Year($)
(a)	(b)	(c)	(d)	(e)
W. B. Timmerman	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	30 30	$921,452 $2,626,901	$0 $0
J. E. Addison	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	17 17	$169,680 $112,299	$0 $0
K. B. Marsh	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	24 24	$497,647 $509,187	$0 $0
S. A. Byrne	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	13 13	$150,608 $253,039	$0 $0
F. P. Mood, Jr.	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	4 4	$76,461 $117,617	$0 $0

(1) Computed as of December 31, 2008, the plan measurement date used for financial statement reporting purposes.

(2)

Present value calculation determined using current account balances for each Named Executive Officer as of the end of 2008, based on assumed retirement at normal retirement age (specified as age 65) and other assumptions as to valuation method, interest rate, discount rate and other material factors as set forth in Note 3 to our audited financial statements for the year ended December 31, 2008, which are included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA in Part II above.

The SCANA Retirement Plan and Supplemental Executive Retirement Plan are both cash balance defined benefit plans. SCE&G participates in these plans. Effective January 1, 2008, the plans provide for full vesting after three years of service or after reaching age 65. All Named Executive Officers are fully vested in both plans.

Defined Benefit Retirement Plan

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

The cash balance formula is expressed in the form of a hypothetical account balance. Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances is determined annually and is equal to the average rate for 30-year Treasury Notes for December of the previous calendar year. Compensation credits equal 5% of compensation up to the Social Security wage base and 10% of compensation in excess of the Social Security wage base.

Supplemental Executive Retirement Plan

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

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2008 NONQUALIFIED DEFERRED COMPENSATION

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

Name	Executive Contributions in Last FY ($)(1)	Registrant Contributions in Last FY ($)(1)	Aggregate Earnings in Last FY ($)(1)	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at Last FYE ($)(1)
(a)	(b)	(c)	(d)	(e)	(f)
W. B. Timmerman	$91,685	$89,029	($219,896)	$0	$2,997,060
J. E. Addison	$17,810	$16,493	($34,164)	$0	$367,312
K. B. Marsh	$61,295	$35,738	($435,964)	$0	$877,663
S. A. Byrne	$24,338	$23,253	($48,607)	$0	$520,929
F. P. Mood, Jr.	$138,811	$17,452	($99,645)	$0	$166,354

(1)

The amounts reported in columns (b) and (c) are reflected in columns (c) and (i), respectively, of the Summary Compensation Table. No amounts in column (d) are reported, or have been previously reported, in the Summary Compensation Table as there were no above market or preferential earnings credited to any Named Executive Officer’s account. The amounts reported in column (f) consisting of Named Executive Officer and Company contributions were previously reported in columns (c) and (i), respectively, of the 2007 and 2006 Summary Compensation Tables in the following amounts: Mr. Timmerman, $171,810 for 2007, $106,440 for 2006; Mr. Addison, $23,406 for 2007, $26,959 for 2006; Mr. Marsh, $67,922 for 2007, $93,806 for 2006; Mr. Byrne, $44,187 for 2007, $81,719 for 2006; and Mr. Mood, $42,920 for 2007, and $47,100 for 2006. For years prior to 2007, amounts would have been included in the Summary Compensation Table when required by the rules of the Securities and Exchange Commission.

Executive Deferred Compensation Plan

We have adopted SCANA’s EDCP, which is a nonqualified deferred compensation plan in which our senior executive officers, including Named Executive Officers, may participate if they choose to do so. Each participant may elect to defer up to 25% of that part of his or her eligible earnings (as defined in SCANA Corporation Stock Purchase Savings Plan, our 401(k) plan), that exceeds the limitation on compensation otherwise required under Internal Revenue Code Section 401(a)(17), without regard to any deferrals or the foregoing of compensation. For 2008, participants could defer eligible earnings in excess of $230,000. In addition, a participant may elect to defer up to 100% of any performance share award for the year under our Long-Term Equity Compensation Plan. We match the amount of compensation deferred by each participant up to 6% of the participant’s eligible earnings (excluding performance share awards) in excess of the Internal Revenue Code Section 401(a)(17) limit.

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

In 2008, the Named Executive Officers’ ledger accounts were credited with earnings (or losses) based on the following hypothetical investment alternatives and rates of returns:

Merrill Lynch Retirement Preservation Trust (+4.50%); PIMCO Total Return (+4.60%); Dodge & Cox Common Stock (-43.31%); American Century Inc. & Growth Adv. (-34.81%); INVESCO 500 Index Trust (-37.20%); American Funds Growth Fund of America (-38.88%); T. Rowe Price Mid Cap Value (-34.57%); Times Square Mid Cap Growth Fund (-33.91%); RS Partners (-38.63%); Vanguard Explorer (-40.40%); American Funds Europacific Growth (-40.53%); SCANA Corporation Stock (-11.34%); Vanguard Target Retirement Income (-10.93%); Vanguard Target Retirement 2005 (-15.82%); Vanguard Target Retirement 2015 (-24.06%); Vanguard Target Retirement 2025 (-30.05%); Vanguard Target Retirement 2035 (-34.66%); Vanguard Target Retirement 2045 (-34.56%).

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

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

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

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

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

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

Potential Payments Upon Termination or Change in Control

Change in Control Arrangements

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

We have adopted the SCANA Corporation Key Executive Severance Benefits Plan and the SCANA Corporation Supplementary Key Executive Severance Benefits Plan, which provide for payments to our senior executive officers in connection with a change in control of our Company. The Key Executive Severance Benefits Plan (the “Severance Plan”) provides for payment of benefits in a lump sum immediately upon a change in control unless the plan has been terminated prior to the change in control. This plan is designed to provide for benefits in the event of a change in control that our Board deems to be hostile. In the event of a change in control that our Board deems to be friendly, we anticipate that the Board would terminate the Severance Plan prior to the change in control. If the Severance Plan is terminated, the Supplementary Key Executive Severance Benefits Plan (the “Supplementary Severance Plan”) would provide for payment of benefits if, within 24 months after the change in control, we terminate a senior executive officer’s employment without just cause or if the senior executive officer terminates his or her employment for good reason.

Our change in control plans are intended to advance the interests of our Company by providing highly qualified executives and other key personnel with an assurance of equitable treatment in terms of compensation and economic security and to induce continued employment with the Company in the event of certain changes in control. We believe that an assurance of equitable treatment will enable valued executives and key personnel to maintain productivity and focus during a period of significant uncertainty inherent in change in control situations. We also believe that compensation plans of this type aid the Company in attracting and retaining the highly qualified professionals who are essential to our success. The structure of the plans, and the benefits which might be paid in the event of a change in control, are reviewed as part of the Human Resources Committee’s annual review of tally sheets for each senior executive officer. The Human Resources Committee has reviewed the structure of the plans and the overall compensation that might be due pursuant to those plans as part of its discussions of plan amendments required to comply with Section 409A.

Both plans provide that a “change in control” will be deemed to occur under the following circumstances:

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

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

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

if SCANA shareholders approve a plan of complete liquidation, or sale or disposition of, South Carolina Electric & Gas Company, Carolina Gas Transmission Corporation (f/k/a South Carolina Pipeline Corporation) or any of SCANA’s other subsidiaries that the Board designates to be a material subsidiary. (This last provision would constitute a change in control only with respect to participants exclusively assigned to the affected subsidiary.)

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

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

·	willfully engaged in conduct that is materially injurious to us; or

·	were convicted of a felony or certain misdemeanors.

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

·	a material diminution in his or her base salary;

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

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

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

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

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

Potential Benefits Payable

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

·	an amount intended to approximate three times the sum of: (i) his or her annual base salary (before reduction for certain pre-tax deferrals) plus (ii) his or her full targeted annual incentive award, in each case as in effect for the year in which the change in control occurs;

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

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

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

In addition to the benefits above, immediately upon a change in control prior to which we had not terminated the Severance Plan (unless their agreements with us provide otherwise), our senior executive officers would also be entitled to benefits under our other plans in which they participate as follows:

·	a benefit distribution of all amounts (or remaining amounts) of pre-2005 deferrals and hypothetical earnings thereon held in each participant’s EDCP ledger account as of the date of the change in control;

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

·	a benefit distribution under the Short-Term Annual Incentive Plan equal to 100% of the target award in effect as of the date of the change in control;

·	any amounts previously earned, but not yet paid, under the terms of any of our other plans or programs; and

under the Long-Term Equity Compensation Plan and related agreements, all nonqualified stock options awarded and non-vested target performance shares would become immediately exercisable or vested and remain exercisable throughout their original term or, in the case of performance shares, vested and payable within 30 days of the change in control.

Whether or not we have terminated the Severance Plan, if the change in control constitutes a permitted change of control distribution event under Internal Revenue Code Section 409A, post-2004 deferrals and hypothetical earnings thereon held in participants’ EDCP ledger accounts as of the date of the change in control will also become immediately due and payable.

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Under the Supplementary Severance Plan, if, within 24 calendar months after a change in control, we terminate the employment of a senior executive officer without just cause, or if a senior executive officer terminates his or her employment for good reason, such senior executive officer would also be entitled to all of the benefits described above. In addition, interest would be paid on the benefits payable under the EDCP at a rate equal to the sum of the prime interest rate as published in the Wall Street Journal on the most recent publication date prior to the date of the change in control plus 3%, calculated through the end of the month preceding the month in which the benefits are distributed. Any amounts payable under the Supplementary Severance Plan would be reduced by all amounts, if any, received under the Severance Plan.

In addition, benefit distributions to senior executive officers under the Severance Plan, the Supplementary Severance Plan, the performance share award portion of our Long-Term Equity Compensation Plan, and any other compensation plan or arrangement would also include payment of an amount (a “gross-up payment”) reimbursing him or her for the amount of anticipated excise tax imposed under Section 4999 of the Internal Revenue Code (or any similar tax) on such benefits and the gross-up payment, and any income, federal Medicare taxes and any additional excise taxes due with respect to the gross-up payment.

Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 31, 2008

Severance Plan

If we had been subject to a change in control as of December 31, 2008, and the Severance Plan had not been terminated, our Named Executive Officers would have been immediately entitled to the benefits outlined below.

Mr. Timmerman would have been entitled to the following: an amount equal to three times his 2008 base salary and target short-term incentive award — $6,099,450; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $533,485; an amount equal to insurance continuation benefits for three years — $40,722; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $4,704,042; an amount equal to the value of 100% of his restricted stock under the Long-Term Equity Compensation Plan — $605,414; and anticipated excise tax and gross-up payment — $5,005,501. The total value of these change in control benefits would have been $16,988,614. In addition, Mr. Timmerman would have been paid amounts previously earned, but not yet paid, as follows: 2008 actual short-term annual incentive award — $653,905; 2008 actual long-term equity award — $2,469,806; EDCP account balance — $2,997,060; SERP and Retirement Plan account balances — $3,693,172; vacation accrual — $25,362; as well as his 401(k) Plan account balance.

Mr. Addison would have been entitled to the following: an amount equal to three times his 2008 base salary and target short-term incentive award — $1,940,871; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $709,059; an amount equal to insurance continuation benefits for three years — $75,240; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $821,221; an amount equal to the value of 100% of his restricted stock under the Long-Term Equity Compensation Plan — $114,774; and anticipated excise tax and gross-up payment — $1,756,316. The total value of these change in control benefits would have been $5,417,481. In addition, Mr. Addison would have been paid amounts previously earned, but not yet paid, as follows: 2008 actual short-term annual incentive award — $164,120; 2008 actual long-term equity award — $306,968; EDCP account balance — $367,312; SERP and Retirement Plan account balances — $355,208; vacation accrual — $14,676; as well as his 401(k) Plan account balance.

Mr. Marsh would have been entitled to the following: an amount equal to three times his 2008 base salary and target short-term incentive award — $2,871,000; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $817,859; an amount equal to insurance continuation benefits for three years — $52,491; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $1,661,844; an amount equal to the value of 100% of his restricted stock under the Long-Term Equity Compensation Plan — $212,995; and anticipated excise tax and gross-up payment — $2,392,913. The total value of these change in control benefits would have been $8,009,102. In addition, Mr. Marsh would have been paid amounts previously earned, but not yet paid, as follows: 2008 actual short-term annual incentive award — $263,900; 2008 actual long-term equity award — $873,728; EDCP account balance — $877,663; SERP and Retirement Plan account balances — $1,182,892; vacation accrual — $7,250; as well as his 401(k) Plan account balance.

Mr. Byrne would have been entitled to the following: an amount equal to three times his 2008 base salary and target short-term incentive award — $2,136,000; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $743,952; an amount equal to insurance continuation benefits for three years — $75,966; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $1,047,922; an amount equal to the value of 100% of his restricted stock under the Long-Term Equity Compensation Plan — $136,206; and anticipated excise tax and gross-up payment — $1,793,141. The total value of these change in control benefits would have been $5,933,187. In addition, Mr. Byrne would have been paid amounts previously earned, but not yet paid, as follows: 2008 actual short-term annual incentive award — $186,900; 2008 actual long-term equity award — $542,437; EDCP account balance — $520,929; SERP and Retirement Plan account balances — $502,694; vacation accrual — $11,125; as well as his 401(k) Plan account balance.

Mr. Mood would have been entitled to the following: an amount equal to three times his 2008 base salary and target short-term incentive award — $1,813,500; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $0; an amount equal to insurance continuation benefits for three years — $57,627; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $802,673; an amount equal to the value of 100% of his restricted stock under the Long-Term Equity Compensation Plan — $105,020; and anticipated excise tax and gross-up payment — $1,270,909. The total value of these change in control benefits would have been $4,049,729. In addition, Mr. Mood would have been paid amounts previously earned, but not yet paid, as follows: 2008 actual short-term annual incentive award — $150,150; 2008 actual long-term equity award — $409,495; EDCP account balance — $166,354; SERP and Retirement Plan account balances — $194,078; vacation accrual — $563; as well as his 401(k) Plan account balance.

In addition to the foregoing benefits, all option and stock awards set forth in the 2008 Outstanding Equity Awards at Fiscal Year-End Table would have vested for each Named Executive Officer.

Supplementary Severance Plan

If (i) we had been subject to a change in control in the past 24 months, (ii) the Severance Plan had been terminated prior to the change in control, and (iii) as of December 31, 2008, either we had terminated the employment of any of our Named Executive Officers without just cause or they had terminated their employment for good reason, such terminated Named Executive Officer would have been immediately entitled to all of the benefits outlined above, together with interest, calculated as outlined above under “— Potential Benefits Payable,” on his EDCP account balance. The actual amount of any such additional payment would depend upon the date on which employment of the Named Executive Officer terminated subsequent to the change in control.

Retirement Benefits

Supplemental Executive Retirement Plan

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

Subject to the terms of the SERP, a participant becomes eligible to receive benefits under the SERP upon termination of his or her employment with us (or at such later date as may be provided in a participant’s agreement with us), if the participant has become vested in his or her accrued benefit under the Retirement Plan prior to termination of employment. However, if a participant is involuntarily terminated following or incident to a change in control and prior to becoming fully vested in his or her accrued benefit under the Retirement Plan, the participant will automatically become fully vested in his benefit under the SERP and a benefit will be payable under the SERP. The term “change in control” has the same meaning in the SERP as in the Severance Plan and the Supplementary Severance Plan. See the discussion under “— Change in Control Arrangements.”

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Subject to the terms of any participant agreement, upon the occurrence of a change in control prior to which the Severance Plan has not been terminated, the actuarial equivalent present value of all grandfathered benefits (or remaining grandfathered benefits) owed under the SERP and each underlying participant agreement as of the date of such change in control will become immediately due and payable. Subject to the terms of any participant agreement, upon the occurrence of a change in control that constitutes a permitted change of control distribution event under Internal Revenue Code Section 409A, regardless of whether the Severance Plan is terminated prior thereto, the actuarial equivalent present value of all non-grandfathered benefits (or remaining non-grandfathered benefits) owed under the SERP and each underlying participant agreement as of the date of such change in control will become immediately due and payable.

All SERP benefits payable upon a change in control will be paid to each participant (and his or her beneficiary) in the form of a single lump sum cash payment of the actuarial equivalent present value of all such amounts owed. Such payments will be made as soon as practicable following the change in control. With respect to grandfathered benefits, if the Severance Plan was terminated prior to such change in control, then payment of the SERP benefits will not be accelerated and participants’ benefits will be determined under the other applicable provisions of the SERP and/or any participant agreement. With respect to non-grandfathered benefits, if the change in control does not constitute a permitted change of control distribution event under Internal Revenue Code Section 409A, then payment of the SERP benefits will not be accelerated and participants’ benefits will be determined and paid under the otherwise applicable provisions of the SERP and/or any participant agreement.

Calculation of Benefits Potentially Payable to our Named Executive Officers Under the SERP if a Triggering Event had Occurred as of December 31, 2008

The lump sum or annuity amounts that would have been payable under the SERP to each of our Named Executive Officers if they had become eligible for benefits as of December 31, 2008 are set forth below. Also set forth below are the payments that would have been made to each Named Executive Officer’s designated beneficiary if the officer had died December 31, 2008.

For Mr. Timmerman, the lump sum amount would have been $2,734,113. Alternatively, Mr. Timmerman could have elected to receive a lump sum of $742,645 as of December 31, 2008 and monthly payments of $12,247 commencing January 1, 2009 for the remainder of his lifetime. In the event Mr. Timmerman had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $7,348 for up to 15 years upon Mr. Timmerman’s death. If Mr. Timmerman had died December 31, 2008 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $2,734,113.

For Mr. Addison, the lump sum amount would have been $141,462. Alternatively, Mr. Addison could have elected to receive a lump sum of $95,403 as of December 31, 2008 and monthly payments of $218 commencing January 1, 2009 for the remainder of his lifetime. In the event Mr. Addison had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $131 for up to 15 years upon Mr. Addison’s death. If Mr. Addison had died December 31, 2008 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $141,462.

For Mr. Marsh, the lump sum amount would have been $598,225. Alternatively, Mr. Marsh could have elected to receive a lump sum of $287,461 as of December 31, 2008 and monthly payments of $1,590 commencing January 1, 2009 for the remainder of his lifetime. In the event Mr. Marsh had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $954 for up to 15 years upon Mr. Marsh’s death. If Mr. Marsh had died December 31, 2008 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $598,225.

For Mr. Byrne, the lump sum amount would have been $315,129. Alternatively, Mr. Byrne could have elected to receive a lump sum of $180,853 as of December 31, 2008 and monthly payments of $644 commencing January 1, 2009 for the remainder of his lifetime. In the event Mr. Byrne had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $386 for up to 15 years upon Mr. Byrne’s death. If Mr. Byrne had died December 31, 2008 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $315,129.

For Mr. Mood, the lump sum amount would have been $117,617. Mr. Mood did not have a pre-2005 balance on which to calculate an annuity benefit. If Mr. Mood had died December 31, 2008 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $117,617.

Executive Deferred Compensation Plan

The EDCP is described in the narrative following the 2008 Nonqualified Deferred Compensation Table. As discussed in that section, amounts deferred under the plan are required to be paid, or begin to be paid, as soon as practicable following the earliest of a participant’s death, termination of employment, or with respect to pre-2005 deferrals and hypothetical earnings thereon, disability. All amounts payable at a date certain prior to termination of employment, death, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability, must be paid in the form of a single cash payment. Payments made after termination of employment, death, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability, will also be paid in the form of a single cash payment. Instead of a single cash payment, a participant may, however, elect to have all amounts payable as a result of termination of employment after attainment of age 55, death while employed and after attainment of age 55, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, termination of employment due to disability, paid in the form of annual installments over a period not to exceed five years with respect to post-2004 deferrals and hypothetical earnings thereon or 15 years with respect to pre-2005 deferrals and hypothetical earnings thereon. All amounts credited to a participant’s ledger account continue to be hypothetically invested among the investment alternatives until such amounts are paid in full to the participant or his or her beneficiary.

The “Aggregate Balance at Last FYE” column of the 2008 Nonqualified Deferred Compensation Table shows the amounts that would have been payable under the EDCP to each of our Named Executive Officers, as of December 31, 2008, (i) with respect to amounts payable at a date certain prior to termination of employment, death, or, as to pre-2005 deferrals and hypothetical earnings thereon, disability, and (ii) with respect to amounts payable after termination of employment, death, or, as to pre-2005 deferrals and hypothetical earnings thereon, disability, if they had been paid using the single sum form of payment. If the Named Executive Officers instead chose payment of the deferrals in annual installments, the annual installment payments over the payment periods selected by the Named Executive Officers are estimated as set forth below: Mr. Timmerman — $599,412; Mr. Addison — $73,462; Mr. Marsh — $175,533; Mr. Byrne — $104,186; and Mr. Mood $33,271.

Discussion of Plans are Summaries Only

The discussions of our various compensation plans in this “Executive Compensation” section of this Item 11 are merely summaries of the plans and do not create any rights under any of the plans, and are qualified in their entirety by reference to the plans themselves.

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DIRECTOR COMPENSATION

Board Fees

Our Board reviews director compensation every year with guidance from the Nominating Committee. In making its recommendations, the Committee is required by our Governance Principles to consider that compensation should fairly pay directors for work required in a company of SCANA’s size and scope, compensation should align directors’ interests with the long-term interests of shareholders, and the compensation structure should be transparent and easy for shareholders to understand. We also consider the risks inherent in board service. Approximately every other year, the Nominating Committee considers relevant publicly available data in making recommendations. The Committee may also consider recommendations from our Chairman and Chief Executive Officer.

Officers who are also directors do not receive additional compensation for their service as directors. Annual compensation for non-employee directors consists of the following:

·	an annual retainer of $45,000 required to be paid in shares of SCANA common stock;

·	a fee of $6,500 for attendance at regular quarterly meetings of the Board of Directors;

·	a fee of $6,000 for attendance at all-day meetings of the Board of Directors other than regular meetings;

·	a fee of $3,000 for attendance at half-day meetings of the Board of Directors other than regular meetings;

·	a fee of $3,000 for attendance at a committee meeting held on a day other than a day a regular meeting of the Board of Directors is held;

·	a fee of $300 for telephonic meetings of the Board of Directors or a committee that last fewer than 30 minutes;

·	a fee of $600 for telephonic meetings of the Board of Directors or a committee that last more than 30 minutes; and

·	reimbursement of reasonable expenses incurred in connection with all of the above.

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

Director Compensation and Deferral Plan

Since January 1, 2001, non-employee director compensation and related deferrals have been governed by the SCANA Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2008, the only director with funds associated with the Voluntary Deferral Plan was Mr. Bennett.

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

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

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

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

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

·	a single sum payment;

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

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

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

Notwithstanding any payment election made by a director:

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

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

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

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

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

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

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

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

·	provide for such other installment payment schedules as SCANA deems appropriate under the circumstances.

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

In the event of a change in control of SCANA, and if the Severance Plan has not been terminated prior to the change in control, the amounts (or remaining amounts) credited to each director’s pre-2005 ledger account will become immediately due and payable. If the change in control constitutes a permitted change of control distribution event under Internal Revenue Code Section 409A, regardless of whether the Severance Plan is terminated prior thereto, the amounts (or remaining amounts) credited to each participant’s post 2004 ledger account as of the date of such change in control will become immediately due and payable. Each such payment will be in the form of a single lump sum cash payment. If the Severance Plan was terminated prior to such change in control, then payment of participants’ benefits with respect to pre-2005 ledger accounts will not be accelerated and such benefits will be determined and paid under the otherwise applicable provisions of the plan. If the change in control does not constitute a permitted change of control distribution event under Internal Revenue Code Section 409A, then payment of participants’ benefits with respect to post-2004 ledger accounts will not be accelerated and such benefits will be determined and paid under the otherwise applicable provisions of the plan.

During 2008, Messrs. Amick, Micali, Roquemore, Sloan, York and Ms. Miller elected to defer 100% of their compensation and earnings and Messrs. Bennett, Hagood and Stowe deferred a portion of their earnings under the Director Compensation and Deferral Plan.

Endowment Plan

Upon election to a second term, a director becomes eligible to participate in the SCANA Director Endowment Plan, which provides for SCANA to make tax deductible, charitable contributions totaling $500,000 to institutions of higher education designated by the director. The plan is intended to reinforce the commitment to quality higher education and to enhance the ability to attract and retain qualified board members. A portion is contributed upon retirement of the director and the remainder upon the director’s death. As of December 31, 2008, the present value of the obligation under the plan was $3,244,231. The plan is funded through insurance policies on the lives of the directors. The 2008 premium for such insurance was $152,339. Currently the premium estimate for 2009 is $150,098.

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

Discussions of Plans are Summaries Only

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

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2008 DIRECTOR COMPENSATION

The following table sets forth the compensation paid to each of our non-employee directors in 2008.

(1)	The annual retainer of $45,000 is required to be paid in SCANA common stock. Shares were purchased on January 7, 2008 and January 8, 2008, at a weighted average purchase price of $42.28 in order to satisfy the retainer fee obligation.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS

SCANA: Information required by Item 12 is incorporated herein by reference to the caption "SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" in SCANA's definitive proxy statement for the 2009 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA's fiscal year.

Equity securities issuable under SCANA's compensation plans at December 31, 2008 are summarized as follows:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders:
Long-Term Equity Compensation Plan	106,464	27.44	3,209,564
Non-Employee Director Compensation Plan	n/a	n/a	n/a
Equity compensation plans not approved by security holders	n/a	n/a	n/a
Total	106,464	27.44	3,209,564

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SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The following table lists shares of SCANA common stock beneficially owned on February 16, 2009, by each director and each person named in the Summary Compensation Table in ITEM 11. EXECUTIVE COMPENSATION and all directors and executive officers as a group.

Name of Beneficial Owner		Amount and Nature of Beneficial Ownership (1)(2)(3)(4)(5)	Percent of Class
W. B.	Timmerman	77,578	*
J. E.	Addison	15,995	*
K. B.	Marsh	26,299	*
S. A.	Byrne	16,240	*
F. P.	Mood, Jr.	4,899	*
B. L.	Amick	62,072	*
J. A.	Bennett	2,908	*
S. A.	Decker	2,306	*
D. M.	Hagood	1,541	*
W. H.	Hipp	20,570	*
J. M.	Micali	1,000	*
L. M.	Miller	3,906	*
J. W.	Roquemore	1,000	*
M. K.	Sloan	2,094	*
H. C.	Stowe	3,125	*
G. S.	York	15,097	*
All executive officers and directors as a group (18 persons)		268,012	*

*Less than 1%

(1)	Includes shares purchased through February 16, 2009, by the Trustee under SCANA’s Stock Purchase Savings Plan.

(2)	Includes Restricted Stock granted on February 14, 2008, subject to a three-year vesting period, in the following amounts: Messrs. Timmerman — 17,006; Addison — 3,224; Marsh — 5,983; Byrne — 3,826; Mood — 2,950 and other executive officers as a group — 3,714.

(3)

Hypothetical shares acquired under the Director Compensation and Deferral Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 16, 2009, the following directors had acquired the following numbers of hypothetical shares: Messrs. Amick — 21,635; Bennett — 19,358; Hagood — 8,289; Hipp — 14,455; Micali — 3,976; Roquemore — 3,807; Sloan — 25,411; Stowe — 16,767; and York — 25,539; Mrs. Decker — 0; and Ms. Miller — 26,512.

(4)

Hypothetical shares acquired under the Executive Deferred Compensation Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 16, 2009, the following officers had acquired the following numbers of hypothetical shares: Messrs. Timmerman — 55,325; Addison — 588; Marsh — 5,649; Byrne — 11,595 and Mood — 0.

(5)	Includes shares owned by close relatives and/or shares held in trust for others, as follows: Messrs. Amick — 480 and Mr. Mood — 500.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related Party Transactions

Each senior executive officer, director and director nominee is required to complete an annual questionnaire and report all transactions with SCANA and any of its subsidiaries, including SCE&G, in which such persons (or their immediate family members) had or will have a direct or indirect material interest (except for salaries and other compensation, directors’ fees and dividends on SCANA stock). It is the general intention of SCANA and SCE&G to avoid such transactions. The General Counsel of SCANA and SCE&G reviews responses to the questionnaires and any other information about related party transactions that may be brought to his attention. If any related party transactions are disclosed, they are reviewed by the Nominating Committee, pursuant to the requirements of its charter. If appropriate, any such transactions are submitted to the Board for approval.

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The types of transactions that have been reviewed in the past include the purchase and sale of goods, services or property from companies for which directors of SCANA and SCE&G serve as executive officers or directors, and the purchase of financial services and access to lines of credit from banks for which directors of SCANA and SCE&G serve as executive officers or directors. During the year ended December 31, 2008, there were no transactions requiring reporting to the Board.

Director Independence

The Board has determined that all of its directors and director nominees, except Mr. Timmerman, who is our Chief Executive Officer, are independent under the New York Stock Exchange Listing Standards and our Governance Principles. The Board has also determined that each member of the Audit Committee, Human Resources Committee, Governance Committee and Nominating Committee is independent under the New York Stock Exchange Listing Standards and our Governance Principles.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

SCANA: The information required by Item 14 is incorporated herein by reference to "PROPOSAL 2 - APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM" in SCANA's definitive proxy statement for the 2008 annual meeting of shareholders.

SCE&G: The Audit Committee Charter requires the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the independent registered accounting firm. Pursuant to a policy adopted by the Audit Committee, its chairman may pre-approve the rendering of services on behalf of the Audit Committee. Decisions to pre-approve the rendering of services by the chairman are presented to the Audit Committee at each of its scheduled meetings.

Independent Registered Public Accounting Firm’s Fees

The following table sets forth the aggregate fees charged to SCE&G and its consolidated affiliates for the fiscal years ended December 31, 2008 and 2007 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

	SCE&G
	2008		2007
Audit Fees(1)	$	1,687,425		$	1,578,546
Audit-Related Fees(2)		64,233			73,105
Tax Fees(3)		-			190
All Other Fees		-			-
Total Fees	$	1,751,658		$	1,651,841

(1)	Fees for audit services billed in 2008 and 2007 consisted of audits of annual financial statements, comfort letters, consents and other services related to Securities and Exchange Commission ("SEC") filings and accounting research.

(2) Fees primarily for employee benefit plan audits for 2008 and 2007.

(3) Fees for tax compliance and tax research services for 2007.

In 2008 and 2007, all of the Audit Fees, Audit Related Fees and Tax Fees were approved by the Audit Committee.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed or furnished as a part of this Form 10-K:

(1) Financial Statements and Schedules:

The Report of Independent Registered Public Accounting Firm on the financial statements for SCANA and SCE&G are listed under Item 8 herein.

The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein.

The financial statement schedules filed as part of this report for SCANA and SCE&G are included below.

(2) Exhibits

Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission (SEC) and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.

Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA's employee stock purchase plan will be furnished under cover of Form 10-K/A to the SEC when the information becomes available.

As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries and of SCE&G, for itself and its consolidated affiliates, have been omitted and SCANA and SCE&G agree to furnish a copy of such instruments to the SEC upon request.

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Schedule II—Valuation and Qualifying Accounts

			Additions
Description	Beginning Balance		Charged to Income		Charged to Other Accounts				Deductions from Reserves		Ending Balance
SCANA:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2008	$	9,940,587	$	14,330,497		$	142,504		$	13,367,968	$	11,045,620
2007		13,988,579		8,623,366			-			12,671,358		9,940,587
2006		24,863,825		16,935,990			-			27,811,236		13,988,579

Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2008	$	7,672,648	$	2,928,653		$	(22,960	)	$	4,167,861	$	6,410,480
2007		9,028,774		6,670,687			107,025			8,133,838		7,672,648
2006		6,328,361		6,734,385			400,895			4,434,867		9,028,774

SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2008	$	1,689,968	$	5,078,232		$	142,504		$	3,859,861	$	3,050,843
2007		5,201,167		(87,797	)		-			3,423,402		1,689,968
2006		1,574,069		7,481,886			-			3,854,788		5,201,167

Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2008	$	6,040,021	$	2,863,562		$	-		$	3,601,296	$	5,302,287
2007		6,908,317		6,098,007			-			6,966,303		6,040,021
2006		4,892,076		5,980,520			-			3,964,279		6,908,317

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	SCANA CORPORATION
	BY:	/s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director
	DATE:	February 27, 2009

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.

	/s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer)
	/s/J. E. Addison J. E. Addison, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
	/s/J. E. Swan, IV J. E. Swan, IV, Controller (Principal Accounting Officer)

Other Directors*:
	B. L. Amick	L. M. Miller
	J. A. Bennett	J. W. Roquemore
	S. A. Decker	M. K. Sloan
	D. M. Hagood	H. C. Stowe
	W. H. Hipp	G. S. York
	J. M. Micali

*Signed on behalf of each of these persons by Francis P. Mood, Jr., Attorney-in-Fact

DATE:

February 27, 2009

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SIGNATURES

	SOUTH CAROLINA ELECTRIC & GAS COMPANY
	BY:	/s/K. B. Marsh K. B. Marsh President and Chief Operating Officer
	DATE:	February 27, 2009

		/s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
		/s/J. E. Addison J. E. Addison, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
		/s/J. E. Swan, IV J. E. Swan, IV, Controller (Principal Accounting Officer)

Other Directors*:
	B. L. Amick	L. M. Miller
	J. A. Bennett	J. W. Roquemore
	S. A. Decker	M. K. Sloan
	D. M. Hagood	H. C. Stowe
	W. H. Hipp	G. S. York
	J. M. Micali

*Signed on behalf of each of these persons by Francis P. Mood, Jr., Attorney-in-Fact

DATE:

February 27, 2009

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EXHIBIT INDEX

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description

3.01	X		Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03		X	Restated Articles of Incorporation of South Carolina Electric & Gas Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.04		X	Articles of Amendment effective as of the dates indicated below and filed as exhibits to the Registration Statements or Exchange Act reports set forth below and are incorporated by reference herein
			May 22, 2001		Exhibit 3.02	to Registration No. 333-65460
			June 14, 2001		Exhibit 3.04	to Registration No. 333-65460
			August 30, 2001		Exhibit 3.05	to Registration No. 333-101449
			March 13, 2002		Exhibit 3.06	to Registration No. 333-101449
			May 9, 2002		Exhibit 3.07	to Registration No. 333-101449
			June 4, 2002		Exhibit 3.08	to Registration No. 333-101449
			August 12, 2002		Exhibit 3.09	to Registration No. 333-101449
			March 13, 2003		Exhibit 3.03	to Registration No. 333-108760
			May 22, 2003		Exhibit 3.04	to Registration No. 333-108760
			June 18, 2003		Exhibit 3.05	to Registration No. 333-108760
			August 7, 2003		Exhibit 3.06	to Registration No. 333-108760
			February 26, 2004		Exhibit 3.05	to Registration No. 333-145208-01
			May 18, 2004		Exhibit 3.06	to Registration No. 333-145208-01
			June 18, 2004		Exhibit 3.07	to Registration No. 333-145208-01
			August 12, 2004		Exhibit 3.08	to Registration No. 333-145208-01
			March 9, 2005		Exhibit 3.09	to Registration No. 333-145208-01
			May 16, 2005		Exhibit 3.10	to Registration No. 333-145208-01
			June 15, 2005		Exhibit 3.11	to Registration No. 333-145208-01
			August 16, 2005		Exhibit 3.12	to Registration No. 333-145208-01
			March 14, 2006		Exhibit 3.13	to Registration No. 333-145208-01
			May 11, 2006		Exhibit 3.14	to Registration No. 333-145208-01
			June 28, 2006		Exhibit 3.15	to Registration No. 333-145208-01
			August 16, 2006		Exhibit 3.16	to Registration No. 333-145208-01
			March 13, 2007		Exhibit 3.17	to Registration No. 333-145208-01
			May 22, 2007		Exhibit 3.18	to Registration No. 333-145208-01
			June 22, 2007		Exhibit 3.19	to Registration No. 333-145208-01
			August 21, 2007		Exhibit 3.01	to Form 8-K filed August 23, 2007
			May 15, 2008		Exhibit 3.01	to Form 8-K filed May 21, 2008
			July 9, 2008		Exhibit 3.01	to Form 8-K filed July 10, 2008
			August 28, 2008		Exhibit 3.01	to Form 8-K filed August 28, 2008

3.05		X	Articles of Correction filed on June 1, 2001 correcting May 22, 2001 Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.06		X	Articles of Correction filed on February 17, 2004 correcting Articles of Amendment for the dates indicated below and filed as exhibits to Registration Statement No. 333-145208-01 set forth below and are incorporated by reference herein
			May 7, 2001	Exhibit 3.21(a)
			May 22, 2001	Exhibit 3.21(b)
			June 14, 2001	Exhibit 3.21(c)

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	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description

			August 30, 2001	Exhibit 3.21(d)
			March 13, 2002	Exhibit 3.21(e)
			May 9, 2002	Exhibit 3.21(f)
			June 4, 2002	Exhibit 3.21(g)
			August 12, 2002	Exhibit 3.21(h)
			March 13, 2003	Exhibit 3.21(i)
			May 22, 2003	Exhibit 3.21(j)
			June 18, 2003	Exhibit 3.21(k)
			August 7, 2003	Exhibit 3.21(l)

3.07		X	Articles of Correction dated March 17, 2006, correcting March 14, 2006 Articles of Amendment (Filed as Exhibit 3.22 to Registration Statement No. 333-145208-01 and incorporated by reference herein)
3.08		X	Articles of Correction dated September 6, 2006, correcting August 16, 2006 Articles of Amendment (Filed as Exhibit 3.23 to Registration Statement No. 333-145208-01 and incorporated by reference herein)
3.09		X	Articles of Correction dated May 20, 2008, correcting May 15, 2008 Articles of Amendment (Filed as Exhibit 3.02 to Form 8-K filed on May 21, 2008 and incorporated by reference herein)
3.10	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 3.01 to Form 8-K filed February 23, 2009 and incorporated by reference herein)
3.11		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
4.01	X	X	Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)
4.02	X		Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein)
4.03		X	Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)
4.04		X	First Supplemental Indenture to Indenture referred to in Exhibit 4.03 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)
4.05		X	Second Supplemental Indenture to Indenture referred to in Exhibit 4.03 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)
*10.01	X	X	Engineering, Procurement and Construction Agreement, dated May 23, 2008, between South Carolina Electric & Gas Company, for itself and as Agent for the South Carolina Public Service Authority and a Consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended March 31, 2008 and incorporated by reference herein)
*10.02	X	X	SCANA Executive Deferred Compensation Plan as amended and restated effective as of January 1, 2009 (Filed herewith)

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	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
*10.03	X	X	SCANA Supplemental Executive Retirement Plan as amended and restated effective as of January 1, 2009 (Filed herewith)
*10.04	X	X	SCANA Director Compensation and Deferral Plan as amended and restated effective as of January 1, 2009 (Filed herewith)
*10.05	X	X	SCANA Executive Benefit Plan as amended and restated effective as of January 1, 2009 (Filed herewith)
*10.06	X	X	SCANA Long-Term Equity Compensation Plan as amended and restated effective as of January 1, 2009 (Filed as Exhibit 4.04 to Post-Effective Amendment No. 1 to Registration Statement No. 333-37398 and incorporated by reference herein)
*10.07	X	X	SCANA Supplementary Executive Benefit Plan as amended and restated effective as of January 1, 2009 (Filed herewith)
*10.08	X	X	SCANA Short-Term Annual Incentive Plan as amended and restated effective as of January 1, 2009 (Filed herewith)
*10.09	X	X	SCANA Key Executive Severance Benefits Plan as amended and restated effective as of January 1, 2009 (Filed herewith)
*10.10	X	X	SCANA Supplementary Key Executive Severance Benefits Plan as amended and restated effective as of January 1, 2009 (Filed herewith)

*10.11	X	X	Description of SCANA Whole Life Option (Filed as Exhibit 10-F for the year ended December 31, 1991, under cover of Form SE, Filed No. 1-8809 and incorporated by reference herein)
10.12		X	Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 10.16 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
12.01	X		Statement Re Computation of Ratios (Filed herewith)
12.02		X	Statement Re Computation of Ratios (Filed herewith)
21.01	X		Subsidiaries of the registrant (Filed herewith under the heading “Corporate Structure” in Part I, Item I of this Form 10-K and incorporated by reference herein)
23.01	X		Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith)
23.02		X	Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith)
24.01	X	X	Power of Attorney (Filed herewith)

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	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
31.01	X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.03		X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.04		X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

* Management Contract or Compensatory Plan or Arrangement

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