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, 2007
OR
o	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 o South Carolina Electric & Gas Company o

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 o

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 o 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 o	Non-accelerated filer o
	Smaller reporting company o

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

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

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

The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $4.5 billion at June 29, 2007 based on the closing price of $38.29 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, 2008
SCANA Corporation	Without Par Value	116,664,933
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 2007 Proxy Statement, in connection with its 2008 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.

		Page
DEFINITIONS		4
PART I
Item 1.	Business	5
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	18
Item 3.	Legal Proceedings	20
Item 4.	Submission of Matters to a Vote of Security Holders	21
Executive Officers of SCANA Corporation		22
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial and Other Statistical Data	25
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	26
	South Carolina Electric & Gas Company	79
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	119
Item 9A.	Controls and Procedures - SCANA Corporation	119
Item 9A(T).	Controls and Procedures - South Carolina Electric & Gas Company	121
Item 9B.	Other Information	121
PART III
Item 10.	Directors and Executive Officers of the Registrant	122
Item 11.	Executive Compensation	125
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	154
Item 13.	Certain Relationships and Related Transactions	155
Item 14.	Principal Accountant Fees and Services	155
PART IV
Item 15.	Exhibits and Financial Statement Schedules	157
SIGNATURES		159
Exhibit Index		161

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
CGTC	Carolina Gas Transmission Corporation
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

PART I

ITEM 1.  BUSINESS

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

South Carolina Electric & Gas Company (SCE&G) generates, transports and sells electricity to retail and wholesale customers and purchases, sells and transports 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. Through its SCANA Energy division, SEMI markets natural gas in Georgia's retail natural gas 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.

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, estimated construction and other expenditures and factors affecting the availability of synthetic fuel tax credits. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:

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

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

(3)         current and future litigation;

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

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

      in industrial interruptible markets;

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

(7)         the results of financing efforts;

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

(9)         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 and construct facilities for baseload 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 its subsidiaries 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.

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, 2008 and 2007 of 5,703 and 5,683, 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, 2008 and 2007 of 3,011 and 2,908, 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

SCANA does not directly own or operate any significant physical properties. SCANA, through its subsidiaries, is engaged in the functionally distinct operations described below. SCANA also has an investment in one limited liability company (LLC) which owns and operates a cogeneration facility in Charleston, South Carolina.

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.

Regulated Utilities

SCE&G generates, transports and sells electricity to 639,300 customers and purchases, sells and transports natural gas to 302,500 customers (each as of December 31, 2007). 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 rubber and plastic, chemicals, health services, paper, retail, metal fabrication, stone, clay and glass, engineering and management services and textile manufacturing.

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 457,200 residential, commercial and industrial customers (as of December 31, 2007). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The industrial customers of PSNC Energy include manufacturers or processors of ceramics and clay products, glass, automotive products, pharmaceuticals, plastics, metals and a variety of food and tobacco products.

CGTC operates as an open access, transportation-only interstate pipeline company regulated by the Federal Energy Regulatory Commission (FERC). CGTC operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural Gas Company (Southern Natural) at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGTC also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transcontinental Gas Pipeline Corporation (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 and county gas authorities, and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles.

Nonregulated Businesses

SEMI markets natural gas primarily in the southeast and provides energy-related risk management services. SCANA Energy, a division of SEMI, markets natural gas to over 475,000 customers (as of December 31, 2007) in Georgia's natural gas market.  The Georgia Public Service Commission (GPSC) has again selected SCANA Energy to serve as the state’s regulated provider until August 31, 2009.  Included in the above customer count, SCANA Energy serves over 95,000 customers (as of December 31, 2007) under this regulated provider contract, which includes low-income and high credit risk customers. SCANA Energy's total customer base represents over a 30% share of the approximately 1.5 million customers in Georgia's 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 1,742 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides tower site construction, management and rental services in South Carolina and North Carolina.

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. 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 three-year period 2008-2010, 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, 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.

CAPITAL PROJECTS

For a discussion of 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 3.03, 2.94, 2.19, 2.65 and 2.82 for the years ended December 31, 2007, 2006, 2005, 2004 and 2003, respectively.  SCE&G’s ratios of earnings to fixed charges were 3.40, 3.32, 2.26, 3.40 and 3.25 for the same periods.  SCE&G’s ratios of earnings to combined fixed charges and preference dividends were 3.17, 3.08, 2.10, 3.15 and 3.01 for the same periods.  SCANA’s and SCE&G’s ratios for 2005 were negatively impacted by the large amounts of accelerated depreciation discussed at Results of Operations - Income Taxes - Recognition of Synthetic Fuel Tax Credits in their respective Management’s Discussion and Analysis of Financial Condition and Results of Operations sections, and because the calculation necessarily excludes the related and fully offsetting tax benefits recorded in that year.

ELECTRIC OPERATIONS

Electric Sales

SCE&G's sales of electricity by customer classification as a percent of electric revenues for 2007 were unchanged from 2006 and were as follows:

Customer Classification
Residential	41	%
Commercial	31	%
Industrial	17	%
Sales for resale	7	%
Other	2	%
Total Territorial	98	%
Negotiated Market Sales Tariff (NMST)	2	%
Total	100	%

Sales for resale include sales to seven municipalities. Sales under the NMST during 2007 include sales to 20 investor-owned utilities or registered marketers, four electric cooperatives and four federal/state electric agencies. During 2006 sales under the NMST included sales to 25 investor-owned utilities or registered marketers, three electric cooperatives, and three federal/state electric agencies.

During 2007 SCE&G recorded a net increase of 15,900 electric customers (growth rate of 2.6%), increasing its total electric customers to 639,300 at year end. During 2007, a new all-time peak demand of 4,926 megawatts (MW) was set on August 10, 2007.

For the three-year period 2008-2010, SCE&G projects total territorial kilowatt hour (KWh) sales of electricity to decrease 0.4% annually (assuming normal weather), total electric customer base to increase 2.4% annually and territorial peak load (summer, in MW) to decrease 0.1% annually.  The projected decrease in KWh sales and territorial peak load result from the scheduled expiration of certain sales for resale contracts.  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 significantly 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 forms part of an interconnected grid extending over a large part of the southern and eastern portions of the nation. SCE&G, Dominion Virginia Power, Duke Power Carolinas, Progress Energy Carolinas, APGI (Yadkin Division) and the South Carolina Public Service Authority (Santee Cooper) are members of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the Southeastern Electric Reliability Council (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.

Fuel Costs and Fuel Supply

The average cost of various fuels and the weighted average cost of all fuels (including oil) for the years 2005-2007 follow:

	Cost of Fuel Used
	2005		2006		2007
Per million British thermal units (MMBTU):
Nuclear	$	.46	$	.43	$	.43
Coal		2.38		2.54		2.53
Gas		10.50		8.18		8.28
All Fuels (weighted average)		2.53		2.57		2.66
Per Ton:
Coal	$	59.07	$	63.13	$	62.98
Per thousand cubic feet (MCF):
Gas	$	10.91	$	8.57	$	8.67

The sources and percentages of total megawatt hour (MWh) generation by each category of fuel for the years 2005-2007 and the estimates for the years 2008-2010 follow:

	% of Total MWh Generated
	Actual							Estimated
	2005			2006		2007		2008		2009		2010
Coal		68	%	67	%	63	%	64	%	65	%	65	%
Nuclear		19	%	19	%	21	%	19	%	19	%	21	%
Hydro		5	%	4	%	4	%	5	%	5	%	5	%
Natural Gas & Oil		8	%	10	%	12	%	12	%	11	%	9	%
Total		100	%	100	%	100	%	100	%	100	%	100	%

Six of the fossil fuel-fired plants use coal. Unit trains and in some cases trucks and barges deliver coal to these plants. On December 31, 2007 SCE&G had approximately a 71-day supply of coal in inventory.

Coal is obtained through long-term supply contracts and spot market purchases. Long-term contracts exist with six suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 4.1 million tons annually, which is 65% of total expected coal purchases for 2008. Sulfur restrictions on the contract coal range from 1.0% to 1.5%. These contracts expire at various times through 2010. Spot market purchases are expected to continue when needed or when prices are 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 the V. C. Summer Nuclear Station (Summer Station) through 2009. 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	20-21	2009
Enrichment	United States Enrichment Corporation	20-24	2014
Fabrication	Westinghouse Electric Corporation	20-22	2011

(a) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region 19 was

loaded in 2006.

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 United States Department of Energy (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.

GAS OPERATIONS

Gas Sales-Regulated

Sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 2006 and 2007 were as follows:

	SCANA						SCE&G
Customer Classification	2006			2007			2006			2007
Residential		42.6	%		51.1	%		38.4	%		40.5	%
Commercial		25.6	%		29.6	%		30.2	%		30.4	%
Industrial		27.6	%		16.1	%		30.7	%		28.4	%
Sales for Resale		0.9	%		-			-			-
Transportation Gas		3.3	%		3.2	%		0.7	%		0.7	%
Total		100	%		100	%		100	%		100	%

For the three-year period 2008-2010, SCANA projects total consolidated sales of regulated natural gas in dekatherms (DT) to increase 1.7% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 2.6%, commercial of 1.5% and industrial 1.1%.

SCANA's total consolidated regulated natural gas customer base is projected to increase 3.3% annually. During 2007 SCANA recorded a net increase of 21,000 regulated gas customers (growth rate of 2.8%), increasing its regulated gas customers to 759,000.  Of this increase, SCE&G recorded a net increase of 5,300 gas customers (growth rate of 1.8%), increasing its total gas customers to 302,500 (as of December 31, 2007).

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 2008 and 2017) and CGTC (expiring 2009). 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 296,629 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 $9.69 per MCF during 2007 and $9.82 per MCF during 2006.

SCE&G was allocated 5,406 MMCF of natural gas storage space on Southern Natural and Transco. Approximately 4,224 MMCF of gas were in storage on December 31, 2007. 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 1,758 MMCF (liquefied equivalent) of gas were in storage at December 31, 2007.

North Carolina

PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at current price indices and on a long-term basis for reliability assurance at index prices plus a reservation charge. Transco and Dominion Transmission, Inc. (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 $8.55 per DT during 2007 compared to $9.47 per DT during 2006.

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 12,800 MMCF. Approximately 11,000 MMCF of gas were in storage at December 31, 2007. In addition, PSNC Energy's own 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, 2007. 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 at December 31, 2007.

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 over 475,000 customers (as of December 31, 2007) in Georgia's natural gas market. SCANA Energy's total customer base represents over a 30% share of the approximately 1.5 million customers in Georgia's deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

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 North Carolina Utilities Commission (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. FERC’s approval expires February 6, 2010.

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 expects to apply to FERC for relicensing of the Saluda project in 2008.

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 United States Nuclear Regulatory Commission (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 and PSNC Energy's gas rate schedules for their residential and small commercial and small industrial customers include a weather normalization adjustment (WNA). SCE&G's and PSNC Energy's WNA were approved by the SCPSC and NCUC, respectively, and are in effect for bills rendered during the period November 1 through April 30 of each year. In each case 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.

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. SCE&G may request a formal proceeding at any time should circumstances dictate such a review.  As part of the annual review of fuel costs, the SCPSC approved SCE&G’s request to increase the cost of fuel component from 2.516 cents per KWh to 2.630 cents per KWh effective the first billing cycle in May 2007. 

SCE&G's gas rate schedules and contracts include mechanisms that allow it to recover from its customers changes in the actual cost of gas. SCE&G's firm gas rates allow for the recovery of the cost of gas, based on projections, as established by the SCPSC. SCE&G adjusts its cost of gas on a monthly basis based on a twelve-month rolling average.

In May 2007, the 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.

In addition to WNA, PSNC Energy’s Rider D rate mechanism serves to reduce fluctuations in PSNC Energy’s earnings. The Rider D mechanism allows PSNC Energy 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 modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually.

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 the consolidated financial statements for SCANA and SCE&G (Note 10B).

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 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 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.

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 and our timely securing of labor and materials at estimated costs.  Recently, certain construction commodities such as steel and concrete have experienced significant price increases due to 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.  Also, higher worldwide demand for copper, which we use in our transmission and distribution lines, has led to significant price increases.  Our ability to maintain our operations or to complete construction projects and new baseload generation (whether based on nuclear or another form of 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) 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 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 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 volatility. To the extent we do not hedge against commodity price 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 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, financial reporting, interaction among affiliates, and the payment of dividends. 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 extensive federal, state and local environmental laws and regulations including air emissions (such as reducing nitrogen oxide, sulfur dioxide and mercury emissions, or potential future control of greenhouse gas emissions).  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 or require us to curtail some of our activities. Costs of compliance with 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.

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, both of which may adversely affect results of operations, cash flows and financial condition.

Changes in interest rates can affect the cost of borrowing on variable rate debt outstanding, on refinancing of debt maturities and on incremental borrowing to fund new investments. 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. The liquidity of the Company and SCE&G would be adversely affected by unfavorable changes in the commercial paper market or if bank credit facilities became unavailable at acceptable rates.

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 debt ratings, thereby increasing its borrowing costs and adversely affecting its results of operations, cash flows and financial condition.

SCANA's leverage ratio of debt to capital increased significantly following its acquisition in 2000 of PSNC Energy, and was approximately 55% at December 31, 2007. SCANA has publicly announced its desire to maintain this leverage ratio at 54% to 55%, 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 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.

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 and Fitch carry a stable outlook on each of their ratings.  S&P carries a negative outlook on each of its 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-1, respectively. If these short-term ratings were to decline, it could significantly limit access to the commercial paper market and other 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 climate which could increase and adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.

Sales and sales growth is 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 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.

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 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.

The V.C. Summer nuclear plant, operated by SCE&G, provided approximately 5.7 million MWh, or 21% of our generation capacity, in 2007.  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;

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, 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 litigation, 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

None 

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. SCANA also has an investment in one LLC which operates a cogeneration facility in Charleston, South Carolina.

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 and natural gas transmission properties, which are further described below. Natural gas distribution properties in South Carolina and North Carolina, though not depicted on the map, are also described below.

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	405
Wateree	Coal	Eastover, SC	1970	700
Williams(2)	Coal	Goose Creek, SC	1973	615
Cope	Coal	Cope, SC	1996	420
Cogen South(3)		Charleston, SC	1999	90
Combined Cycle:
Urquhart(4)	Coal/Gas/Oil	Beech Island, SC	1953/2002	562
Jasper	Gas/Oil	Hardeeville, SC	2004	852
Hydro(5):
Saluda		Irmo, SC	1930	206
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 horse power from Cogen South, LLC to operate SCE&G's generator. Cogen South, LLC is

             owned 50% by SCANA and 50% by MeadWestvaco.

(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 18 MW.

SCE&G owns nine 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 354 MW.

SCE&G owns 442 substations having an aggregate transformer capacity of 27.6 million KVA (kilovolt-ampere). The transmission system consists of 3,239 miles of lines, and the distribution system consists of 18,010 pole miles of overhead lines and 6,035 trench miles of underground lines.

NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES

SCE&G’s natural gas system consists of 15,406 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 1,473 miles of transmission pipeline of up to 24 inches in diameter, which connect its transportation customers’ distribution systems with the transmission systems of Southern Natural and Transco and can supply gas from Port Wentworth and Elba Island, Georgia.

PSNC Energy’s natural gas system consists of 923 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 9,285 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, 2007, 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 United States Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater.  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 site has not been remediated nor has a clean-up cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries,  is expected to be recoverable through rates.

SCE&G has been named, along with 29 others, by the EPA as a PRP at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  In 2008, SCE&G, along with other parties, reached a settlement with the EPA and the U.S. Department of Justice on this matter.  The settlement, which is subject to court approval, would result in an allocation of cost to SCE&G that is not material, and such cost is expected to be recoverable through rates.

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 $11.9 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 through rates.  At December 31, 2007, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $16.7 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 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 $4.6 million, which reflects its estimated remaining liability at December 31, 2007.  PSNC Energy expects to recover any costs, net of insurance recoveries, allocable to PSNC Energy arising from the remediation of these sites through rates.

Litigation

 On February 26, 2008, a purported class action lawsuit styled as David K. Weiskircher and J. Steven Parker, on behalf of themselves and all others similarly situated v. SCANA Energy Marketing, Inc. was filed in U.S. District Court for the Northern District of Georgia.  The plaintiffs allege, among other things, that SCANA Energy charged certain of its customers a price for natural gas and customer service charges that exceeded SCANA Energy’s published price effective at the beginning of their monthly billing cycles, and that such action violated the Natural Gas Competition and Deregulation Act.  The plaintiffs do not assert a specific dollar amount for the claims, but do demand actual damages, punitive damages, treble damages pursuant to the Georgia Fair Business Practices Act, as well as interest, attorneys' fees and costs.  SCANA Energy has not been served with this lawsuit and has not yet had the opportunity to evaluate it.

b

In May 2004, SCANA and SCE&G were served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA 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 overruled 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 plaintiff appealed this ruling to the South Carolina Court of Appeals and the Court of Appeals has dismissed the appeal, determining that the Circuit Court ruling is not immediately appealable.  Plaintiff’s motion for class certification was recently heard and correspondence from the Circuit Court indicates the judge’s intention to certify the class.  There has been no formal order and the class remains limited to easements in Charleston County.  SCANA 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.

A complaint was filed in October 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The claim against SCE&G was settled by an agreement between the parties, and the settlement was approved in 2004 by South Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit.  In addition, SCE&G filed a petition with the SCPSC in October 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. SCANA and SCE&G believe that the resolution of these matters 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.

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	61	Chairman of the Board, President and Chief Executive Officer	*-present
Jimmy E. Addison	47	Senior Vice President and Chief Financial Officer Vice President-Finance	2006-present *-2006
Joseph C. Bouknight	55	Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA	2004-present *-2004
George J. Bullwinkel	59	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	50	Senior Vice President-Fuel Procurement and Asset Management-SCE&G and PSNC Energy Senior Vice President-Fuel Procurement and Asset Management-SCPC	2003-present *-2006
Stephen A. Byrne	48	Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G Senior Vice President-Nuclear Operations	2004-present *-2004
Paul V. Fant	54	President and Chief Operating Officer-CGTC (formerly SCPC and SCG Pipeline) Senior Vice President Transmission Services – SCE&G Executive Vice President-SCPC and SCG Pipeline	2004-present 2004-2007 *-2004
Kevin B. Marsh	52	President and Chief Operating Officer - SCE&G Senior Vice President and Chief Financial Officer	2006-present *-2006
Charles B. McFadden	63	Senior Vice President-Governmental Affairs and Economic Development- SCANA Services	*-present
Francis P. Mood, Jr.	70	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, 2003.

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):

	2007						2006
	4th Qtr.		3rd Qtr.		2nd Qtr.	1st Qtr.	4th Qtr.			3rd Qtr.		2nd Qtr.	1st Qtr.
High	$43.73	$39.75		$45.49		$43.51		$42.43	$41.65		$40.41			$41.42
Low	$38.69	$32.93		$37.91		$39.92		$39.55	$38.35		$36.92			$39.02

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, 2008 there were 116,664,933 shares of SCANA Common Stock outstanding which were held by 32,995 stockholders of record. For a summary of equity securities issuable under SCANA's compensation plans at December 31, 2007, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

SCANA declared quarterly dividends on its common stock of $.44 per share in 2007 and $.42 per share in 2006. On February 14, 2008, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.46 per share, an increase of 4.5%. The new dividend is payable April 1, 2008 to stockholders of record on March 10, 2008. 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.

The following table provides information about purchases by or on behalf of SCANA or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended (Exchange Act)) of shares or other units of any class of SCANA’s equity securities that are registered pursuant to Section 12 of the Exchange Act:

Issuer Purchases of Equity Securities
			(c)	(d)
			Total number of	Maximum number
	(a)		shares (or units)	(or approximate dollar
	Total number of	(b)	purchased as part of	value) of shares (or units_
	shares (or units)	Average price paid	publicly announced	that may yet be purchased
Period	purchased	per share (or unit)	plans or programs	under the plan or program
October 1-31	317,389	39.00	317,389
November 1-30	80,594	41.23	80,594
December 1-31	91,215	43.14	91,215
Total	489,198		489,198	*

*On May 16, 2006 SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans.  This program has no stated maximum number of  shares that may be purchased and no stated expiration date.

SCE&G: All of SCE&G's common stock is owned by SCANA and is not traded. During 2007 and 2006 SCE&G paid $131.9 million and $151.5 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, 2008)

	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
Standard & Poor’s (S&P)	BBB+	A-	BBB+	BBB	A-2	Negative
Fitch	A-	A+	A	A-	F-1	Stable

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.

ITEM 6. SELECTED FINANCIAL AND OTHER STATISTICAL DATA

	SCANA															SCE&G
As of or for the Year Ended December 31,	2007			2006			2005			2004			2003			2007			2006			2005			2004			2003
	(Millions of dollars, except statistics and per share amounts)
Statement of Income Data
Operating Revenues	$	4,621		$	4,563		$	4,777		$	3,885		$	3,416		$	2,481		$	2,391		$	2,421		$	2,089		$	1,832
Operating Income		633			603			436			596			551			498			468			312			475			440
Other Income (Expense)		(160	)		(164	)		(162	)		(219	)		(138	)		(117	)		(121	)		(121	)		(111	)		(101	)
Income Before Cumulative Effect of Accounting Change		320			304			320			257			282			245			230			258			232			220
Net Income (1)	$	320		$	310		$	320		$	257		$	282		$	245		$	234		$	258		$	232		$	220
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions)		116.7			115.8			113.8			111.6			110.8			n/a			n/a			n/a			n/a			n/a
Basic and Diluted Earnings Per Share (1)	$	2.74		$	2.68		$	2.81		$	2.30		$	2.54			n/a			n/a			n/a			n/a			n/a
Dividends Declared Per Share of Common Stock	$	1.76		$	1.68		$	1.56		$	1.46		$	1.38			n/a			n/a			n/a			n/a			n/a
Balance Sheet Data
Utility Plant, Net	$	7,538		$	7,007		$	6,734		$	6,762		$	6,417		$	6,202		$	5,748		$	5,580		$	5,621		$	5,293
Total Assets		10,165			9,817			9,519			9,006			8,458			7,977			7,626			7,366			6,985			6,628
Capitalization:
Common equity	$	2,960		$	2,846		$	2,677		$	2,451		$	2,306		$	2,622		$	2,457		$	2,362		$	2,164		$	2,043
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			8			8			9			9			7			8			8			9			9
Long-term Debt, net		2,879			3,067			2,948			3,186			3,225			2,003			2,008			1,856			1,981			2,010
Total Capitalization	$	5,952		$	6,027		$	5,739		$	5,752		$	5,646		$	4,738		$	4,579		$	4,332		$	4,260		$	4,168
Other Statistics
Electric:
Customers (Year-End)		639,258			623,402			609,971			591,435			577,014			639,312			623,453			610,025			591,497			577,068
Total sales (Million KWh)		24,885			24,519			25,305			25,027			22,512			24,888			24,538			25,323			25,046			22,527
Generating capability-Net MW     (Year-End)		5,749			5,749			5,808			5,817			4,880			5,749			5,749			5,808			5,817			4,880
Territorial peak demand-Net MW		4,926			4,820			4,820			4,574			4,474			4,926			4,820			4,820			4,574			4,474
Regulated Gas:
Customers (Year-End)		759,336			738,317			716,794			693,172			672,849			302,469			297,165			291,607			284,355			278,463
Sales, excluding transportation     (Thousand Therms) (2)		823,976			997,173			1,106,526			1,124,555			1,205,730			407,204			403,489			410,700			399,601			399,392
Retail Gas Marketing:
Retail customers (Year-End)		484,565			482,822			479,382			472,468			415,573			n/a			n/a			n/a			n/a			n/a
Firm customer deliveries     (Thousand Therms)		340,743			335,896			379,913			379,712			356,256			n/a			n/a			n/a			n/a			n/a
Nonregulated interruptible customer   deliveries (Thousand Therms)		1,548,878			1,239,926			1,010,066			917,875			735,902			n/a			n/a			n/a			n/a			n/a

(1) Reflects the 2006 adoption of Statement of Financial Accounting Standards (SFAS) 123(R), recorded as the

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

(2) 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.

			Page
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		27
		Overview	27
		Results of Operations	30
		Liquidity and Capital Resources	37
		Environmental Matters	40
		Regulatory Matters	43
		Critical Accounting Policies and Estimates	44
		Other Matters	46
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		47
Item 8.	Financial Statements and Supplementary Data		49
		Report of Independent Registered Public Accounting Firm	49
		Consolidated Balance Sheets	50
		Consolidated Statements of Income	52
		Consolidated Statements of Cash Flows	53
		Consolidated Statements of Changes in Common Equity and Comprehensive Income	54
		Notes to Consolidated Financial Statements	55

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

OF OPERATIONS

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

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

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

% of Revenues (a)	2007			2006				2005
Regulated		66	%		69		%		69	%
Nonregulated		34	%		31		%		31	%
% of Net Income (b)
Regulated		92	%		89	%			92	%
Nonregulated		8	%		11	%			8	%
% of Assets
Regulated		92	%		93		%		94	%
Nonregulated		8	%		7		%		6	%

(a)  In 2007, revenues reflects the change in business model in 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 related to certain litigation associated with the Company’s prior sale of its propane assets upon the settlement of that litigation. See Results of Operations for more information.

Key earnings drivers for the Company over the next five years 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 in each of the regulated utility businesses, consistent earnings in the natural gas marketing business in Georgia and controlling the growth of operation and maintenance expenses.

Electric Operations

The electric operations segment is comprised of the electric operations of SCE&G, 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, 2007 SCE&G provided electricity to 639,300 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%, with rates set at 10.7%. Demand for electricity is primarily affected by weather, customer growth and the economy.  SCE&G is able to recover the cost of fuel used in electric generation through retail customers' bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

Legislative and regulatory initiatives, including the Energy Policy Act of 2005 (the “Energy Policy Act”) also could significantly impact the results of operations and cash flows for the electric operations segment. The Energy Policy Act became law in August 2005, and it provided, among other things, for the establishment of an electric reliability organization (ERO) to propose and enforce mandatory reliability standards for transmission systems and for procedures governing enforcement actions by the ERO and Federal Energy Regulatory Commission (FERC). 

Consistent with reliability provisions of the Energy Policy Act, on July 20, 2006, FERC issued a final rule certifying the North American Electric Reliability Council (NERC) as the ERO.  On March 16, 2007, FERC issued a final rule establishing mandatory, enforceable reliability standards for the nation’s bulk power system. In the final rule, FERC approved 83 of the 107 mandatory reliability standards submitted by the NERC and compliance with these standards became mandatory on June 18, 2007. FERC has subsequently approved 8 critical infrastructure protection standards which are mandatory and enforceable.  The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities.

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

Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy, and is primarily engaged in the purchase, transmission and sale of natural gas to retail customers in portions of North Carolina and South Carolina. At December 31, 2007 this segment provided natural gas to 759,700 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 were not experienced in 2007 or 2006, 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 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.

Effective November 1, 2006 SCG Pipeline merged into South Carolina Pipeline Corporation (SCPC) and the merged company changed its name to Carolina Gas Transmission Corporation.  Prior to the merger, the gas transmission segment was comprised solely of SCPC, which owned and operated an intrastate pipeline engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G) and industrial customers throughout most of South Carolina. SCPC’s operating results were primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers.

Retail Gas Marketing

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to over 475,000 customers (as of December 31, 2007) throughout Georgia. SCANA Energy’s total customer base represents over a 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. SCANA Energy’s competitors include affiliates of other large energy companies with experience in Georgia’s energy market as well as several electric membership cooperatives. SCANA Energy’s ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors.

As Georgia’s regulated provider, SCANA Energy serves low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the Georgia Public Service Commission (GPSC), and it receives funding from the Universal Service Fund for some of the bad debt associated with the low-income group. SCANA Energy’s service as Georgia’s regulated provider of natural gas ends August 31, 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, 2007, SCANA Energy’s regulated division served over 95,000 customers.

SCANA Energy and SCANA’s other natural gas distribution and marketing segments maintain gas inventory and also utilize forward contracts and financial instruments, including 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.

In February 2008 the consumer affairs staff (the staff) of the GPSC alleged to the GPSC that SCANA Energy and the state's largest natural gas marketer (the marketers) had overcharged certain of their respective customers.  The staff alleges that the marketers failed to inform customers with more expensive rate plans that a lower rate plan was available, charged customers in excess of the published price, and failed to give proper notice of a change in methodology for computing variable rates.  SCANA Energy believes it complied with all applicable rules and regulations, that none of its customers were treated unfairly, and that all requests it received from customers to be switched to a lower rate plan were honored. SCANA Energy has responded that these types of pricing plans exist in many deregulated markets, such as telecommunications, and are a natural development in a competitive environment. The GPSC has indicated that it may launch a formal investigation into the matter, and is expected to rule on the matter on March 4, 2008.  Separately, without admitting fault, the other marketer has offered to settle the matter before the GPSC by agreeing to improve communications and to pay $1 million to the Low Income Home Energy Assistance Program.  SCANA Energy is currently in discussions with the GPSC to settle the matter.  While the Company cannot determine 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.

On February 26, 2008, a purported class action was filed in U.S. District Court for the Northern District of Georgia, 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.  SCANA Energy has not been served with this lawsuit and has not yet had the opportunity to evaluate it.

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 tied to the market share held by SCANA Energy in the retail market.

The Company’s reported earnings are prepared in accordance with 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 performance 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:

	2007		2006			2005
Reported (GAAP) earnings per share	$	2.74	$	2.68		$	2.81
Deduct:
Cumulative effect of accounting change, net of tax		-		(.05	)		-
Reduction in charge related to propane litigation		-		(.04	)		-
Gains from sales of telecommunications investments		-		-			(.03	)
GAAP-adjusted net earnings from operations per share	$	2.74	$	2.59		$	2.78
Cash dividends declared (per share)	$	1.76	$	1.68		$	1.56

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. Realized gains in 2005 were recognized on sales of telecommunications investments.

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), the effect on per share earnings of transactions involving the Company’s telecommunications investments and 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	2007		2006		2005
Income Statement Impact:
Reduction in employee benefit costs	$	2.5	$	0.7	$	4.3
Other income		13.7		12.3		11.9
Balance Sheet Impact:
Reduction in capital expenditures		0.8		0.3		1.3
Component of amount due to Summer Station co-owner		0.4		0.2		0.6
Total Pension Income	$	17.4	$	13.5	$	18.1

For the last several years, the market value of the Company’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Among the reasons income in 2007 was higher than income in 2006 was favorable asset investment experience. Among the reasons 2006’s income was lower than 2005’s was a reduction of the assumed rate of return on plan assets from 9.25% to 9%.  See also the discussion of pension accounting in Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 3.3% of income before income taxes in 2007, 2.0% in 2006 and 1.4% in 2005.

Electric Operations

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

Millions of dollars	2007		% Change			2006		% Change			2005
Operating revenues	$	1,954.1		4.1	%	$	1,877.6		(1.6	)%	$	1,908.3
Less: Fuel used in generation		662.3		7.7	%		615.1		(0.5	)%		618.3
Purchased power		32.7		18.9	%		27.5		(26.1	)%		37.2
Margin	$	1,259.1		2.0	%	$	1,235.0		(1.4	)%	$	1,252.8

• 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.

• 2006 vs 2005 Margin decreased by $20.8 million due to unfavorable weather, by $16.0 million due to decreased off-system sales and by $6.5 million due to lower industrial sales. These decreases were offset by residential and commercial customer growth of $26.5 million. Purchased power cost decreased due to lower volumes.

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

Classification (in thousands)	2007		% Change			2006		% Change			2005
Residential		7,814		2.8	%		7,598		(0.5	)%		7,634
Commercial		7,469		3.0	%		7,249		1.9	%		7,117
Industrial		6,267		1.4	%		6,183		(6.0	)%		6,581
Sales for resale (excluding interchange)		2,100		1.2	%		2,076		(5.5	)%		2,197
Other		563		6.8	%		527		0.8	%		523
Total territorial		24,213		2.5	%		23,633		(1.7	)%		24,052
Negotiated Market Sales Tariff (NMST)		672		(24.2	)%		886		(29.3	)%		1,253
Total		24,885		1.5	%		24,519		(3.1	)%		25,305

• 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.

• 2006 vs 2005 Territorial sales volumes decreased by 307 MWh due to lower industrial sales volumes and by 406 MWh due to unfavorable weather. These decreases were partially offset by an increase of 408 MWh due to residential and commercial customer growth.

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	2007		% Change			2006		% Change			2005
Operating revenues	$	1,096.4		1.7	%	$	1,078.0		(7.8	)%	$	1,168.6
Less: Gas purchased for resale		764.6		(2.9	)%		787.1		(12.0	)%		894.6
Margin	$	331.8		14.1	%	$	290.9		6.2	%	$	274.0

• 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.

• 2006 vs 2005 Margin increased by $17.5 million due to increased retail gas base rates which became effective with the first billing cycle in November 2005 and by $4.0 million due to an SCPSC-approved increase in retail gas base rates effective with the first billing cycle in November 2006. These increases were offset by $4.0 million due to lower firm margin resulting from customer conservation at SCE&G. The NCUC-approved rate increase at PSNC Energy, for services rendered on or after November 1, 2006, increased margin by $2.4 million, but was offset primarily by customer conservation.

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

Classification (in thousands)	2007		% Change			2006		% Change			2005
Residential		34,544		5.1	%		32,879		(13.2	)%	37,860
Commercial		26,573		3.3	%		25,718		(7.3	)%	27,750
Industrial		21,281		0.3	%		21,209		1.8	%	20,833
Transportation gas		31,154		3.3	%		30,147		8.8	%	27,698
Total		113,552		3.3	%		109,953		(3.7	)%	114,141

• 2007 vs 2006 Residential, commercial and transportation gas sales volumes increased primarily due to customer growth.

• 2006 vs 2005 Residential and commercial sales volumes decreased primarily due to milder weather and conservation. Transportation sales volumes increased primarily due to interruptible customers using gas instead of alternate fuels.

Gas Transmission

Gas Transmission is comprised of the operations of CGTC and, for periods prior to the November 2006 merger and name change, SCPC and SCG Pipeline for all periods presented. Gas transmission sales margins (including transactions with affiliates) were as follows:

Millions of dollars	2007		% Change			2006		% Change			2005
Transportation revenue	$	49.1		85.3	%	$	26.5		40.2	%	$	18.9
Other operating revenues		-		*			475.0		(26.5	)%		646.3
Less: Gas purchased for resale		-		*			439.2		(27.3	)%		604.2
Margin	$	49.1		(21.2	)%	$	62.3		2.1	%	$	61.0

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

• 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.

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

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

Classification (in thousands)	2007		% Change			2006		% Change			2005
Commercial		-		*			23		(57.4	)%		54
Industrial		-		*			18,875		(17.0	)%		22,748
Transportation		108,626		88.8	%		57,546		27.7	%		45,055
Sales for resale		-		*			33,327		(23.8	)%		43,763
Total		108,626		(1.0	)%		109,771		(1.7	)%		111,620

*Change not meaningful due to change in business model.

• 2007 vs 2006 Transportation volumes increased as a result of the change to an open access, transportation-only interstate pipeline company effective November 1, 2006.

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

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	2007		% Change			2006		% Change			2005
Operating revenues	$	584.2		(3.9	)%	$	608.1		(8.4	)%	$	664.0
Net income		27.5		(8.6	)%		30.1		24.9	%		24.1

• 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.

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

Delivered volumes totaled 34.1 million DT in 2007, 33.6 million DT in 2006 and 37.9 million DT in 2005.

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	2007		% Change			2006			% Change			2005
Operating revenues	$	1,167.7		23.1	%	$	948.7			0.3	%	$	945.5
Net income (loss)		2.8		*			(0.4	)		(33.3	)%		(0.6	)

*Greater than 100%.

• 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.

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

Delivered volumes totaled 154.9 million DT in 2007, 123.9 million DT in 2006 and 101.0 million DT in 2005.  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. Delivered volumes increased in 2006 compared to 2005 primarily as a result of increased service to electric generation facilities and municipalities in Georgia and South Carolina. 

Other Operating Expenses

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

Millions of dollars	2007		% Change			2006		% Change			2005
Other operation and maintenance	$	648.2		4.7	%	$	619.2		(2.0	)%	$	632.0
Depreciation and amortization		323.4		(2.7	)%		332.4		(34.8	)%		509.9
Other taxes		160.2		5.5	%		151.8		4.7	%		145.0
Total	$	1,131.8		2.6	%	$	1,103.4		(14.3	)%	$	1,286.9

• 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 net property additions.  Other taxes increased primarily due to higher property taxes.

• 2006 vs 2005 Other operation and maintenance expenses decreased by $13.9 million due to lower bad debts and by $9.5 million due to lower operating and customer service expenses, both at retail gas marketing, and by $22.5 million due to decreased incentive compensation expense. These decreases were partially offset by $14.2 million due to increased generation, transmission and distribution expenses, by $3.6 million due to lower pension income and by $2.0 million due to higher customer service expenses at SCE&G. Depreciation and amortization expense decreased by $185.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2006 (see Income Taxes - Recognition of Synthetic Fuel Tax Credits), partially offset by $6.7 million due to property additions and higher depreciation rates at SCE&G. Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities and the activities of certain non-regulated subsidiaries. Other income (expense) declined in 2007 compared to 2006 primarily due to lower royalties earned in connection with the operation by a former subsidiary of a synthetic fuel plant. Components of other income (expense) were as follows:

Millions of dollars		2007		% Change				2006		% Change				2005
Other revenues	$	90.3			(36.2	)%	$	141.6			(42.9	)%	$	248.1
Other expenses		(48.2	)		(48.2	)%		(93.1	)		(53.5	)%		(200.3	)
Gain on sale of investments		-			-			-			(100.0	)%		7.2
Gains on sales of assets		9.5			*			3.4			100.0	%		1.7
Total	$	51.6			(0.6	)%	$	51.9			(8.5	)%	$	56.7

* Greater than 100%

• 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 of interest income 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.

• 2006 vs 2005 Other revenues decreased $91.5 million due to lower power marketing activities, $10.8 million due to the termination of a contract to operate a steam combustion turbine at the United States Department of Energy (DOE) Savannah River Site and by $4.3 million due to lower carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project and lower management service fees of $10.0 million, as discussed at Income Taxes - Recognition of Synthetic Fuel Tax Credits below. These decreases were partially offset by higher interest income of $9.4 million and higher third-party coal sales revenue of $4.8 million.   Other expenses decreased by $90.6 million due to lower power marketing activities and $4.4 million due to the termination of the DOE’s Savannah River Site contract. These decreases were partially offset by increased charges in 2006 of $8.7 million related to the settlement of the FERC power marketing matter and higher expenses to support third-party coal sales of $3.6 million.

Interest Expense

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

Millions of dollars	2007		% Change			2006		% Change			2005
Interest on long-term debt, net	$	174.5		(8.6	)%	$	190.9		(4.3	)%	$	199.5
Other interest expense		31.8		70.1	%		18.7		48.4	%		12.6
Total	$	206.3		(1.6	)%	$	209.6		(1.2	)%	$	212.1

• 2007 vs 2006 Interest on long-term debt in 2007 compared to 2006 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.

• 2006 vs 2005 Interest on long-term debt decreased primarily due to reduced long-term borrowings, partially offset by increased variable rates. Other interest expense increased primarily due to increased short-term borrowings.

Income Taxes

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

Recognition of Synthetic Fuel Tax Credits

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. Under an accounting methodology approved by the SCPSC in a January 2005 order, construction costs related to the Lake Murray back-up dam project are recorded in utility plant in service in a special dam remediation account, outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.  The synthetic fuel tax credit program expired at the end of 2007.

The level of depreciation expense and related tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account declines as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. In addition, SCE&G records non-cash carrying costs on the unrecovered investment.  The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2007 and 2006 are as follows:

Millions of dollars	2007				2006		2005
Depreciation and amortization expense	$	(8.4	)	$	(28.2	)	$	(214.0	)
Income tax benefits:
From synthetic fuel tax credits		16.7			30.0			179.0
From accelerated depreciation		3.2			10.8			81.8
From partnership losses		7.0			7.8			28.9
Total income tax benefits		26.9			48.6			289.7
Losses from Equity Method Investments		(18.5	)		(20.4	)		(75.7	)
Impact on Net Income	$	-		$	-		$	-

The 2007 amounts are estimates based on preliminary benchmark information and reflect the likelihood that credits available in 2007 will be phased down pursuant to regulations which limit the credits based on the relative commodity price of crude oil.  Amounts in 2005 reflect the recognition of previously deferred tax credits.  See discussion below.

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

The benchmark price range for 2006 resulted in a phase-out of 33% for 2006. SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2007 also are likely to be impacted by the phase-out calculation. As such, in 2007 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 32.7% of credits generated in 2007 will be available (phase-out of 67.3%).  The U. S. Government is expected to publish the benchmark price range for 2007 in the second quarter of 2008, after which the Company will finalize its estimate of available credits.

The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation.  To the extent that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs will likely be sought. As of December 31, 2007, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $68.4 million.  The Company expects these costs to be recoverable through rates.

Finally, SCANA, through a subsidiary, provided management and maintenance services for a non-affiliated synthetic fuel production facility. Reduced synthetic fuel tax credit availability under the above phase-out provisions also adversely impacted the level of payment SCANA received for these services.  These services ceased on December 31, 2007, concurrent with the expiration of the synthetic fuel tax credit program.

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

SCE&G expects to add additional base load electric generation in the 2015 to 2016 timeframe.  Based on an evaluation of alternatives, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) have selected the Summer Station site as the preferred site if new nuclear generation is built. Due to the significant lead time required for construction of nuclear generation, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) that would cover two new nuclear units. The COL application, if submitted, would be reviewed by the NRC for an estimated three years. SCE&G is uncertain if or when a COL would be submitted to the NRC.  While SCE&G’s current plans are to pursue the development of one or both of these nuclear units, these plans will continue to be influenced by many factors, including NRC licensing attainment, ongoing evaluation of relative construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

In May 2007, the Base Load Review Act (the Act) became law in South Carolina.  This law is intended to allow a utility to recover prudently incurred capital and operating costs associated with new nuclear or coal-fired base load electric generating facilities larger than 350 megawatts.  Based on an application filed by the utility under the Act, the SCPSC would review and rule on the prudency of the decision to build the plant.  If the decision was found to be prudent, that finding would be binding on all future proceedings so long as the plant is constructed in accordance with the schedules, estimates and projections set forth in the approved application.  In addition, beginning with the initial proceeding, the utility would 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 the utility’s updated cost of debt and capital structure.  The cost of service and rate design would be based on the rates approved in the utility’s most recent electric rate order.  The utility may choose to file for a project-specific return on common equity or use the return from its most recent rate proceeding if the proceeding is less than five years old.

SCANA's leverage ratio of debt to capital was approximately 55% at December 31, 2007. SCANA has publicly announced its desire to maintain this leverage ratio at 54% to 55%, 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 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.

The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2008-2010, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars	2008		2009		2010
SCE&G:
Electric Plant:
Generation (including GENCO)	$	481	$	351	$	652
Transmission		47		60		52
Distribution		171		168		172
Other		40		41		19
Nuclear Fuel		6		27		74
Gas		65		61		67
Common and other		13		11		7
Total SCE&G		823		719		1,043
Other Companies Combined		167		161		126
Total	$	990	$	880	$	1,169

The Company’s contractual cash obligations as of December 31, 2007 are summarized as follows:

Contractual Cash Obligations

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)	$	6,344	$	1,201	$	1,263	$	663	$	3,217
Capital leases		2		1		1		-		-
Operating leases		36		16		14		1		5
Purchase obligations		592		338		253		1		-
Other commercial commitments		7,247		1,391		2,050		1,070		2,736
Total	$	14,221	$	2,947	$	3,581	$	1,735	$	5,958

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

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, and no further contributions are anticipated until after 2010. Cash payments under the health care and life insurance benefit plan were $11.4  million in 2007, 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.

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 10G 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 indebtedness. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.

Cash outlays for 2007 (actual) and 2008 (estimated) for certain expenditures are as follows:

Millions of dollars	2007		2008
Property additions and construction expenditures, including nuclear fuel, net of AFC	$	725	$	986
Investments		10		-
Total	$	735	$	986

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.

Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC authority to issue short-term debt.  The FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 6, 2010.

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

Millions of dollars	SCANA			SCE&G			PSNC Energy
Lines of credit:
Committed long-term (total and available, expire December 2011)	$	200		$	650		$	250
Uncommitted (a):
Total		78			-			-
Used by SCANA		7			-			-
Available for use		71			-			-
Short-term borrowings outstanding:
Bank loans/commercial paper (270 or fewer days)	$	7		$	464		$	157
Weighted average interest rate		5.10	%		5.74	%		5.74	%

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

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. The 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 currently outstanding First Mortgage Bonds and all of its future mortgage-backed debt (Bonds) has been and will be issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, 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, 2007, the Bond Ratio was 7.08.

SCE&G’s Restated Articles of Incorporation (Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders unless net earnings (as therein defined) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times (1.5) 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, 2007, the Preferred Stock Ratio was 2.08.

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, 2007, the Ten Percent Test would have limited total issuances of unsecured indebtedness to approximately $445.4 million. Unsecured indebtedness at December 31, 2007, totaled $436.3 million, and was comprised primarily of short-term borrowings.

Financing Cash Flows

During 2007 the Company experienced net cash outflows related to financing activities of $67 million primarily due to the payment of dividends, which were partially offset by net increases in short-term borrowings.

The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. Payments received upon termination of such swaps are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. At December 31, 2007, the estimated fair value of the Company’s swaps totaled a $0.6 million gain related to combined notional amounts of $16.0 million.

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.

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 December 2007 SCANA issued $40 million of the Floating Rate Senior Notes.  The balance of the notes are to be issued at intervals between December 2008 and June 2009.   At December 31, 2007 the estimated fair value of the Company’s forward starting interest rate swap related to the Floating Rate Senior Notes totaled $7.2 million (loss).  

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 Bonds.  The loss of approximately $14.0 million on the settlement of these swaps will be amortized over the 30-year life of the Bonds.

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

On February 14, 2008, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.46 per share, an increase of 4.5%. The new dividend is payable April 1, 2008 to stockholders of record on March 10, 2008.

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 Air Mercury Rule (CAMR), 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, 2007, the Company’s capital expenditures for environmental control totaled $261.3 million. These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $34.4 million during 2007, $28.7 million during 2006, and $25.2 million during 2005.  It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $280.2 million for 2008 and $306.6 million for the four-year period 2009-2012. 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 primary 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 renewable portfolio standard (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.

At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2007.  The Company cannot predict whether such legislation will be introduced or enacted in 2008, 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 CAIR as 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 sets 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 have challenged the rule, seeking a change in the method CAIR uses to allocate sulfur dioxide emission allowances. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements.  Although compliance plans and costs to comply with the rule have not been determined, it is believed that such costs will be material and will be recoverable through rates.

The EPA issued a final rule referred to as CAMR in 2005 establishing a mercury emissions cap and trade program for coal-fired power plants that required limits to be met in two phases, in 2010 and 2018. 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 cannot predict the effect of this ruling on implementation of CAMR state implementation plans (SIPS) and newly promulgated CAMR regulations by the states.

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’s compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet CAIR regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $450 million over the 2007-2010 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $2.4 million in 2010 and $16 million in 2011 and each year thereafter. To meet compliance requirements for the years 2012-2016, SCE&G and GENCO anticipate additional capital expenditures totaling approximately $480 million.

Water Quality

The Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the Clean Water Act, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all, and renewed for nearly all, of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the Clean Water Act. Such legislation may include limitations to 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 DOE in 1983.  As of December 31, 2007, 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 on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. 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 site has not been remediated nor has a clean-up cost been estimated.  Although a basis for the allocation of

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

SCE&G has been named, along with 29 others, by the EPA as a PRP at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from approximately 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  In 2008, SCE&G, along with other parties, reached a settlement with the EPA and the U.S. Department of Justice on this matter.  The settlement, which is subject to court approval, would result in an allocation of cost, net of insurance recoveries, to SCE&G that is not material, and such cost 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 $11.9 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 through rates.  At December 31, 2007, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $16.7 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 $4.6 million, which reflects its estimated remaining liability at December 31, 2007. PSNC Energy expects to recover through rates any costs, net of insurance recoveries, allocable to PSNC Energy arising from the remediation of these sites through rates.

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

South Carolina Electric & Gas Company

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

In May 2007, the 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.

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.

On February 27, 2008, PSNC Energy filed a letter of intent with the NCUC indicating its intention to file an application for a general increase in its rates and charges on or about March 28, 2008.

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 2007, PSNC Energy has achieved a completion rate of eighty-five percent.  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 $6.5 million for the initial assessments, not including any subsequent remediation that may be required. Effective November 1, 2004 the NCUC authorized deferral accounting for certain expenses incurred to comply with DOT’s pipeline integrity management requirements. In accordance with an October 2006 NCUC rate order, $1.4 million in costs incurred and deferred through June 30, 2006 are now being recovered through rates over a three-year period.  Additionally, the rate order approved continuance of deferred accounting treatment for certain pipeline integrity management expenses until resolution of PSNC Energy’s next general rate proceeding.

Carolina Gas Transmission Corporation

CGTC has approximately 74 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.

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

Utility Regulation

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

The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2007, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $2.3 billion and $517 million, respectively.

Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of the Company’s utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. Accounts receivable included unbilled revenues of $175.5 million at December 31, 2007 and $177.6 million at December 31, 2006, compared to total revenues for each year 2007 and 2006 of $4.6 billion.

Provisions for Bad Debts and Allowances for Doubtful Accounts

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

Nuclear Decommissioning

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

SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. 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 and as such, net pension income is reflected in the financial statements (see Results ofOperations-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 $17.4 million recorded in 2007 reflects the use of a 5.85% discount rate, derived using a cash flow matching technique, and an assumed 9.0% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.60% in 2007 would have decreased 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 2007 would have been reduced by $2.2 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.   The plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 7.8%, 10.7%, 11.4% and 12.0%, respectively, all of which have been in excess of related broad indices. The 2007 expected long-term rate of return of 9.0% was based on a target asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2008, the expected rate of return will be 9.0%.

The pension trust is adequately funded, and no contributions have been required since 1997. Management does not anticipate the need to make pension contributions until after 2012.

Similar to its pension accounting, the Company follows SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS 158, in accounting for the cost of its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 5.85%, derived using a cash flow matching technique, and recorded a net SFAS 106 cost of $17.9 million for 2007. Had the selected discount rate been 5.60%, the expense for 2007 would have been $0.7 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, 2007, the Company has recorded an ARO of $99 million for nuclear plant decommissioning (as discussed above) and an ARO of $209 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.

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, 2007 Millions of dollars	2008	2009	2010	2011	2012	Thereafter	Total	Fair Value
Long-Term Debt Issued:
Fixed Rate ($)	123.2	108.2	16.4	620.9	267.1	1,793.3	2,929.1	2,983.5
Average Fixed Interest Rate (%)	5.96	6.27	6.83	6.78	6.23	5.92	6.15
Variable Rate ($)	100.0						100.0	100.1
Average Variable Interest Rate (%)	5.27						5.27
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	3.2	3.2	3.2		16.0	0.6
Average Pay Interest Rate (%)	8.02	8.02	8.02	8.02	8.02		8.02
Average Receive Interest Rate (%)	8.75	8.75	8.75	8.75	8.75		8.75
Pay Fixed/Receive Variable ($)			1.6	1.6	1.6	35.2	40.0	(7.2)
Average Pay Interest Rate (%)			6.47	6.47	6.47	6.47	6.47
Average Receive Interest Rate (%)			5.78	5.78	5.78	5.78	5.78

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

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 $72 million at December 31, 2007 and $80 million at December 31, 2006, 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.  The notes are to be issued at intervals between December 2007 and June 2009.  In December 2007 SCANA issued $40 million of the Floating Rate Senior Notes.  At December 31, 2007 the estimated fair value of the Company’s forward starting interest rate swap related to $40 million of the Floating Rate Senior Notes is depicted in the table above.

In the fourth quarter 2007 SCE&G entered into several 30-year forward starting swap agreements in anticipation of its proposed issuance of  $250 million in debt no later than February 29, 2008.  At December 31, 2007 the estimated fair value of SCE&G’s forward starting interest rate swaps related to this expected debt issuance totaled $6.3 million (loss).  On January 14, 2008 SCE&G issued $250 million of its First Mortgage Bonds having an annual interest rate of 6.05% and maturing on January 15, 2038.  SCE&G terminated the forward starting interest rate swaps concurrent with the issuance of the debt.  This debt and related swaps are not reflected in the table 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	Sold Put
2008	Long	Short		(Long)	(Short)	(Long)
Settlement Price (a)	7.90	7.50	Strike Price (a)	8.54	10.85	6.09
Contract Amount (b)	34.4	2.4	Contract Amount (b)	10.8	3.1	1.5
Fair Value (b)	32.5	2.2	Fair Value (b)	0.4	-	-
2009
Settlement Price (a)	8.76	-
Contract Amount (b)	30.8	-
Fair Value (b)	30.0	-
2010
Settlement Price (a)	8.98	-
Contract Amount (b)	3.5	-
Fair Value (b)	3.1	-
(a) Weighted average, in dollars
(b) Millions of dollars

Swaps	2008	2009	2010
Commodity Swaps:
Pay fixed/receive variable (b)	168.1	47.1	13.7
Average pay rate (a)	8.687	8.960	9.717
Average received rate (a)	7.804	8.729	8.949
Fair Value (b)	151.0	45.9	12.6
Pay variable/receive fixed (b)	3.5	-	-
Average pay rate (a)	8.645	-	-
Average received rate (a)	7.756	-	-
Fair Value (b)	3.2	-	-
Basis Swaps:
Pay variable/receive variable (b)	31.9	6.8	4.2
Average pay rate (a)	7.853	8.775	8.685
Average received rate (a)	7.854	8.749	8.689
Fair Value (b)	31.9	6.8	4.1
(a) Weighted average, in dollars
(b) Millions of dollars

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

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

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, 2007 and 2006, and the related consolidated statements of income, changes in common equity and comprehensive income, and of cash flows for each of the three years in the period ended December 31, 2007. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SCANA Corporation and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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.

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

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),  the Company’s internal control over financial reporting as of December 31, 2007, 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 29, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/Deloitte & Touche LLP

Columbia, South Carolina

February 29, 2008

SCANA Corporation

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2007			2006
Assets
Utility Plant In Service	$	9,807		$	9,227
Accumulated Depreciation and Amortization		(2,981	)		(2,815	)
		6,826			6,412
Construction Work in Progress		400			326
Nuclear Fuel, Net of Accumulated Amortization		82			39
Acquisition Adjustments		230			230
Utility Plant, Net		7,538			7,007
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $84 and $70		131			132
Assets held in trust, net-nuclear decommissioning		62			56
Other investments		82			88
Nonutility Property and Investments, Net		275			276
Current Assets:
Cash and cash equivalents		134			201
Receivables, net of allowance for uncollectible accounts of $10 and $14		641			655
Receivables-affiliated companies		29			32
Inventories (at average cost):
Fuel		286			300
Materials and supplies		107			93
Emission allowances		33			22
Prepayments and other		62			39
Deferred income taxes		9			34
Total Current Assets		1,301			1,376
Deferred Debits and Other Assets:
Pension asset, net		224			200
Emission allowances		-			27
Regulatory assets		712			792
Other		115			139
Total Deferred Debits and Other Assets		1,051			1,158
Total	$	10,165		$	9,817

December 31, (Millions of dollars)	2007		2006
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,960	$	2,846
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		3,066		2,952
Preferred Stock, Net (Subject to purchase or sinking funds)		7		8
Long-Term Debt, Net		2,879		3,067
Total Capitalization		5,952		6,027
Current Liabilities:
Short-term borrowings		627		487
Current portion of long-term debt		233		43
Accounts payable		401		414
Accounts payable-affiliated companies		27		27
Customer deposits and customer prepayments		85		85
Taxes accrued		156		121
Interest accrued		51		51
Dividends declared		53		51
Other		88		126
Total Current Liabilities		1,721		1,405
Deferred Credits and Other Liabilities:
Deferred income taxes, net		944		947
Deferred investment tax credits		104		120
Asset retirement obligations		307		292
Postretirement benefits		185		194
Regulatory liabilities		830		714
Other		122		118
Total Deferred Credits and Other Liabilities		2,492		2,385
Commitments and Contingencies (Note 10)		-		-
Total	$	10,165	$	9,817

See Notes to Consolidated Financial Statements.

SCANA Corporation

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, (Millions of dollars, except per share amounts)	2007			2006			2005
Operating Revenues:
Electric	$	1,954		$	1,877		$	1,909
Gas-regulated		1,105			1,257			1,405
Gas-nonregulated		1,562			1,429			1,463
Total Operating Revenues		4,621			4,563			4,777
Operating Expenses:
Fuel used in electric generation		662			615			618
Purchased power		33			28			37
Gas purchased for resale		2,161			2,213			2,399
Other operation and maintenance		648			619			632
Depreciation and amortization		324			333			510
Other taxes		160			152			145
Total Operating Expenses		3,988			3,960			4,341
Operating Income		633			603			436
Other Income (Expense):
Other income		90			142			248
Other expenses		(48	)		(93	)		(200	)
Interest charges, net of allowance for borrowed funds used during construction of $13, $8 and $3		(206	)		(209	)		(212	)
Gain on sale of investments and assets		9			3			9
Preferred dividends of subsidiary		(7	)		(7	)		(7	)
Allowance for equity funds used during construction		2			-			-
Total Other Expense		(160	)		(164	)		(162	)
Income Before Income Taxes (Benefit) Losses from   Equity Method Investments and Cumulative Effect of Accounting Change		473			439			274
Income Tax Expense (Benefit)		140			119			(118	)
Income Before Losses from Equity Method Investments
and Cumulative Effect of Accounting Change		333			320			392
Losses from Equity Method Investments		(13	)		(16	)		(72	)
Cumulative Effect of Accounting Change, net of taxes		-			6			-
Net Income	$	320		$	310		$	320
Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change	$	2.74		$	2.63		$	2.81
Cumulative Effect of Accounting Change, net of taxes		-			.05			-
Basic and Diluted Earnings Per Share	$	2.74		$	2.68		$	2.81
Weighted Average Common Shares Outstanding (Millions)		116.7			115.8			113.8

See Notes to Consolidated Financial Statements.

  SCANA Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2007			2006			2005
Cash Flows From Operating Activities:
Net Income	$	320		$	310		$	320
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		-			(6	)		-
Excess losses (earnings), net of distributions from equity method investments		14			23			72
Depreciation and amortization		330			347			518
Amortization of nuclear fuel		19			17			18
Gain on sale of assets and investments		(9	)		(3	)		(9	)
Hedging activities		7			(15	)		4
Allowance for equity funds used during construction		(2	)		-			-
Carrying cost recovery		(6	)		(7	)		(11	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		17			218			(174	)
Inventories		(41	)		(80	)		(188	)
Prepayments and other		(23	)		(2	)		-
Pension asset		(16	)		(13	)		(17	)
Other regulatory assets		40			(32	)		(28	)
Deferred income taxes, net		22			5			25
Regulatory liabilities		94			9			(159	)
Postretirement benefits		7			(3	)		6
Accounts payable		(38	)		(77	)		79
Taxes accrued		35			9			(20	)
Interest accrued		-			(1	)		1
Changes in fuel adjustment clauses		(19	)		3			(7	)
Changes in other assets		13			30			(17	)
Changes in other liabilities		(34	)		21			54
Net Cash Provided From Operating Activities		730			753			467
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(712	)		(485	)		(366	)
Proceeds from sale of assets and investments		10			21			10
Nonutility property additions		(13	)		(42	)		(19	)
Investments		(10	)		(25	)		(18	)
Net Cash Used For Investing Activities		(725	)		(531	)		(393	)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock		6			79			84
Proceeds from issuance of debt		40			132			221
Repayments of debt		(34	)		(156	)		(470	)
Redemption/repurchase of equity securities		(14	)		-			(1	)
Dividends		(210	)		(198	)		(181	)
Short-term borrowings, net		140			60			216
Net Cash Used For Financing Activities		(72	)		(83	)		(131	)
Net Increase (Decrease) in Cash and Cash Equivalents		(67	)		139			(57	)
Cash and Cash Equivalents, January 1		201			62			119
Cash and Cash Equivalents, December 31	$	134		$	201		$	62
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $13, $8 and $3)	$	172		$	212		$	213
-Income taxes		76			100			58
Noncash Investing and Financing Activities:
Accrued construction expenditures		82			54			36

  See Notes to Consolidated Financial Statements. 

SCANA Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME

									Other
	Common Stock					Retained			Comprehensive
Millions	Shares		Amount			Earnings			Income (Loss)			Total
Balance as of December 31, 2004	113	$	1,248		$	1,207		$	(4	)	$	2,451
Comprehensive Income (Loss):
Net Income						320						320
Other Comprehensive Income (Loss), net of taxes $-									-			-
Total Comprehensive Income						320			-			320
Issuance of Common Stock upon Exercise of Options	2		84									84
Dividends Declared on Common Stock						(178	)					(178	)
Balance as of December 31, 2005	115		1,332			1,349			(4	)		2,677
Comprehensive Income (Loss):
Net Income						310						310
Other Comprehensive Income (Loss), net of taxes $(8)									(14	)		(14	)
Total Comprehensive Income						310			(14	)		296
Deferred Cost of Employee Benefit Plans, net of taxes $(7)									(11	)		(11	)
Issuance of Common Stock 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 (Loss)
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

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

See Notes to Consolidated Financial Statements.

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. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) 71, “Accounting for the Effects of Certain Types of Regulation,” which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable.

B.      Basis of Accounting

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

	December 31,
Millions of dollars	2007		2006
Regulatory Assets:
Accumulated deferred income taxes	$	161	$	174
Under-collections-electric fuel and gas cost adjustment clauses		45		95
Environmental remediation costs		26		29
Asset retirement obligations and related funding		274		264
Franchise agreements		52		55
Deferred regional transmission organization costs		5		8
Deferred employee benefit plan costs		120		142
Other		29		25
Total Regulatory Assets	$	712	$	792

Regulatory Liabilities:
Accumulated deferred income taxes	$	35	$	38
Over-collections-electric fuel and gas cost adjustment clauses		19		8
Other asset removal costs		643		599
Storm damage reserve		49		44
Planned major maintenance		15		6
Monetization of bankruptcy claim		45		-
Other		24		19
Total Regulatory Liabilities	$	830	$	714

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

Under- and over-collections - electric fuel and gas cost adjustment clauses, net, represent amounts under- or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings. Included in these amounts are regulatory assets or liabilities arising from realized and unrealized gains and losses incurred in the natural gas hedging programs of the Company’s regulated operations. In addition, certain reagents used to treat fuel emissions are included. See Notes 1E and 1L.

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 $16.7 million remain to be recovered. SCE&G is authorized to amortize $1.4 million of these costs annually.  Costs incurred through June 30, 2006, at sites owned by PSNC Energy are being recovered through rates over a three-year period.  In addition, management believes that costs incurred subsequent to June 30, 2006, totaling $2.2 million at December 31, 2007, and the estimated remaining costs of $4.6 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 an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

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

Deferred employee benefit plan costs represent amountsof 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).

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 and certain transmission and distribution insurance premiums.  In 2007, $1.4 million was drawn from the reserve.  No significant amounts were drawn in 2006.  (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 is allowed to collect $8.5 million annually over an eight-year period, beginning in January 2005, 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 and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets represent costs which have not been approved for recovery by a state commission. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C.      Utility Plant and Major Maintenance

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

SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) jointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G’s portion of Summer Station was $1.0 billion as of December 31, 2007 and 2006 (including amounts related to ARO). Accumulated depreciation associated with SCE&G’s share of Summer Station was $513.1 million and $496.8 million as of December 31, 2007 and 2006, 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 $86.7 million in 2007, $77.5 million in 2006 and $76.3 million in 2005.

Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, SCE&G is collecting $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2007, SCE&G incurred $11.6 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 October 2006 and is accruing $1.1 million per month for its portion of the outage scheduled for the spring of 2008. Total costs for the 2006 outage were $25.8 million, of which SCE&G was responsible for $17.2 million. As of December 31, 2007 and 2006, SCE&G had an accrued balance of $12.7 million and $0.2 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 6.2% for 2007, 5.5% for 2006 and 4.9% for 2005.  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 $175.5 million at December 31, 2007 and $177.6 million at December 31, 2006.

Fuel costs 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. SCE&G had overcollected through the electric fuel cost component $11.4 million at December 31, 2007 which amounts are included in other regulatory liabilities.  SCE&G had undercollected $28.9 million at December 31, 2006 which amounts are included in other regulatory assets.

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the state commission during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual hearing. At December 31, 2007 SCE&G had overcollected $7.5 million which amounts are also included in other regulatory liabilities.  At December 31, 2006 SCE&G had undercollected $20.3 million which amounts are also included in other regulatory assets. At December 31, 2007 and 2006, PSNC Energy had undercollected $44.5 million, net, and $38.5 million, net, respectively, which amounts are included in other regulatory assets.

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

F.      Depreciation and Amortization

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

	2007		2006				2005
SCE&G	3.16	%		3.19	%	3.20		%
GENCO	2.66	%		2.66	%	2.66		%
CGTC	2.00	%		2.04	%	2.01		%
PSNC Energy	3.28	%		3.69	%	3.77		%
Aggregate of Above	3.12	%		3.19	%	3.20		%

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. These calculations have indicated no need for further write-downs of acquisition adjustments.  Should a write-down be required in the future, such a charge would be treated as an operating expense.

G.     Nuclear Decommissioning

SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. 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 2007, 2006 and 2005) 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.

L.      Commodity Derivatives

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

M.     New Accounting Matters

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

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

SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. 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 is not expected to have an impact on the Company’s results of operations, cash flows or financial position.

SFAS 157, “Fair Value Measurements,” was issued in September 2006.  SFAS 157 establishes a framework for measuring fair value to increase the consistency and comparability in fair value measurements.  The Company will adopt SFAS 157 in the first quarter of 2008, and has determined that the adoption will not have a material impact on the Company’s results of operations, cash flows or financial position.  The Company believes it will likely be required to provide additional disclosures as part of future financial statements, beginning with first quarter 2008.

FIN 48, “Accounting for Uncertainty in Income Taxes,” prescribes the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes financial statement recognition threshold and measurement attributes for tax positions taken or expected to be taken in tax returns. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted FIN 48 in the first quarter of 2007.  (See Note 8).

FASB Staff Position (FSP) AUG AIR-1 “Accounting for Planned Major Maintenance Activities,” amended APB 28, “Interim Financial Reporting,” to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance.  As disclosed in Note 1A, the Company has received specific SCPSC orders providing for use of accrue-in-advance accounting for certain planned major maintenance activities. Accordingly, the Company will continue to follow accrue-in-advance  accounting as allowed under SFAS 71 for these activities. The Company’s adoption of FSP AUG AIR-1 in the first quarter of 2007 had no impact on 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 no securities that would have an antidilutive effect on earnings per share.

O.      Affiliated Transactions

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G’s receivables from these affiliated companies were $28.8 million and $31.8 million at December 31, 2007 and 2006, respectively. SCE&G’s payables to these affiliated companies were $26.9 million and $26.6 million at December 31, 2007 and 2006, respectively. SCE&G purchased synthetic fuel from these affiliated companies of $281.6 million in 2007, $291.1 million in 2006 and $248.1 million in 2005.  SCE&G’s investment in the two partnerships will be liquidated in 2008 as a result of the expiration of the synthetic fuel tax credit program at the end of 2007.

SCE&G purchases shaft horsepower from a cogeneration facility.  The facility is owned by a limited liability company (LLC) in which SCANA holds an equity method investment.  SCE&G’s payables to the LLC were $2.1 million and $2.5 million at December 31, 2007 and 2006, respectively.  SCE&G purchased shaft horsepower from the LLC of $27.7 million in 2007, $27.0 million in 2006 and $24.0 million in 2005.

The Company received cash distributions from equity investees of $7.8 million in 2007, $6.7 million in 2006 and $7.1 million in 2005. The Company made cash investments in equity investees of $16.2 million in 2007, $18.4 million in 2006 and $17.7 million in 2005.

Summarized combined financial information of unconsolidated affiliates as of and for the years ended December 31, 2007, 2006 and 2005, is presented below:

		2007			2006			2005
		Millions of dollars
Current assets	$	76		$	78		$	76
Non-current assets		306			324			340
Current Liabilities		80			64			62
Non-current liabilities		302			338			354
Revenues		428			467			380
Gross profit		98			123			62
Loss before income tax benefit		(58	)		(42	)		(40	)

P.           Use of Estimates

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

2.       RATE AND OTHER REGULATORY MATTERS

SCE&G

Electric

In December 2007 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 agreed rate increase produces a 10.7% return).  The new rates became effective January 1, 2008.

In the December 2007 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 was recognized in 2007, 2006 or 2005.

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.

In May 2007, the 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.

In January 2005 the SCPSC approved SCE&G’s application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray back-up dam project were recorded in a special dam remediation account outside of rate base, and depreciation was recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits. The Company expects these costs to be recoverable through rates.

Gas

In October 2007 the SCPSC approved an increase in retail natural gas rates of 0.9% under the terms of the Natural Gas Rate Stabilization Act (Stabilization Act).  The Stabilization Act is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas service infrastructure.  The rate adjustment was effective with the first billing cycle in November 2007.

SCE&G's rates are calculated using a methodology approved by the SCPSC in October 2006 which authorized SCE&G to adjust its cost of gas on a monthly, rather than an annual, basis beginning in December 2006.   The cost of gas adjustment is based on a twelve-month rolling average.

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

PSNC Energy

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

In October 2007, in connection with PSNC Energy’s 2007 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, 2007.

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 new rates are 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.

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

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,	2007		2006		2007			2006
	Millions of Dollars
Fair value of plan assets	$	929.5	$	912.5		-			-
Benefit obligations		704.8		713.0	$	196.8		$	206.9
Funded status		224.7		199.5		(196.8	)		(206.9	)

Amounts recognized on the balance sheets consist of:

	Pension Benefits				Other Postretirement Benefits
December 31,	2007		2006		2007			2006
			Millions of dollars
Noncurrent asset	$	224.7	$	199.5		-			-
Current liability		-		-	$	(11.9	)	$	(12.9	)
Noncurrent liability		-		-		(184.9	)		(194.0	)

Deferred amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2007 and 2006, and amounts recognized in other comprehensive income during the year were as follows:

	Pension Benefits								Other Postretirement Benefits
		Prior										Prior
		Service			Actuarial					Transition		Service			Actuarial
		Cost			Losses		Total			Obligation		Costs			Losses			Total
Balance, December 31, 2006	$	0.9		$	6.6	$	7.5		$	0.6	$	0.6		$	2.4		$	3.6
Current year actuarial (gains) losses		-			0.9		0.9			-		-			(0.9	)		(0.9	)
Amortization of actuarial losses		-			-		-			-		-			(0.1	)		(0.1	)
Current year prior service credits		0.1			-		0.1			-		-			-			-
Amortization of year prior service cost		(0.1	)		-		(0.1	)		-		(0.2	)		-			(0.2	)
Balance, December 31, 2007	$	0.9		$	7.5	$	8.4		$	0.6	$	0.4		$	1.4		$	2.4

The estimated transition obligation, prior service costs and actuarial losses for the defined benefit plans that will be amortized from accumulated other comprehensive income into net periodic benefit costs during 2008 are less than $300,000 in aggregate.

Changes in Benefit Obligations

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2007			2006			2007			2006
Benefit obligation, January 1	$	713.0		$	711.5		$	206.9		$	202.1
Service cost		15.3			14.0			4.4			4.6
Interest cost		40.5			39.8			11.7			11.5
Plan participants' contributions		-			-			2.6			2.1
Plan amendments		7.5			0.6			-			4.0
Actuarial (gain) loss		(25.1	)		(14.4	)		(14.8	)		(5.5	)
Benefits paid		(46.4	)		(38.5	)		(14.0	)		(11.9	)
Benefit obligation, December 31	$	704.8		$	713.0		$	196.8		$	206.9

The accumulated benefit obligation for retirement benefits at the end of 2007 and 2006 was $668.3 million and $666.6 million, respectively. These accumulated retirement benefit obligations differ from the projected retirement benefit obligations above in that they reflect no assumptions about future compensation levels.

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

					Other
	Pension				Postretirement
	Benefits				Benefits
	2007		2006		2007			2006
Annual discount rate used to determine benefit obligations	6.25	%	5.85	%		6.30	%		5.85	%
Assumed annual rate of future salary increases for projected benefit obligation	4.00	%	4.00	%		4.00	%		4.00	%

A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2007. The rate was assumed to decrease gradually to 5.0% for 2013 and to remain at that level thereafter. The postretirement benefit obligation would increase by $2.4 million if the Company increased by one percentage point the assumed healthcare cost trend rate.  The obligation would decrease by $2.1 million if a one percentage point decrease in the assumed trend rate occurred.

Changes in Plan Assets

	Retirement Benefits
Millions of dollars	2007			2006
Fair value of plan assets, January 1	$	912.5		$	854.3
Actual return on plan assets		63.4			96.7
Benefits paid		(46.4	)		(38.5	)
Fair value of plan assets, December 31	$	929.5		$	912.5

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 the end of 2007 and 2006, the fair value of plan assets for the pension plan exceeded both the projected benefit obligation and the accumulated benefit obligation discussed previously.

In connection with the joint ownership of Summer Station, as of December 31, 2007 and 2006, the Company recorded within deferred credits a $4.3 million and $3.6 million obligation, respectively, to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the pension plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. As of December 31, 2007 and 2006, the Company also recorded within deferred debits a $9.5 million and $9.9 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.

Expected Cash Flows

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

			Other Postretirement Benefits*
Expected Benefit Payments	Pension Benefits		Excluding Medicare Subsidy		Including Medicare Subsidy
	Millions of dollars
2008	$	49.9	$	12.5	$	12.2
2009		51.9		13.1		12.7
2010		53.6		13.6		13.3
2011		61.1		13.9		13.5
2012		63.5		14.0		13.7
2013-2017		322.5		76.5		75.0

* Net of participant contributions

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	2007			2006			2005			2007			2006		2005
Service cost	$	15.3		$	14.0		$	12.2		$	4.4		$	4.6	$	3.5
Interest cost		40.5			39.8			38.3			11.7			11.5		10.7
Expected return on assets		(79.8	)		(75.2	)		(76.3	)		n/a			n/a		n/a
Prior service cost amortization		6.6			6.8			6.9			1.1			1.1		0.8
Amortization of actuarial loss		-			0.5			-			0.9			1.7		1.2
Transition amount amortization		-			0.6			0.8			(0.2	)		0.8		0.8
Net periodic benefit (income) cost	$	(17.4	)	$	(13.5	)	$	(18.1	)	$	17.9		$	19.7	$	17.0

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

	Pension Benefits									Other Postretirement Benefits
	2007			2006			2005			2007		2006			2005
Discount rate		5.85	%		5.60	%		5.75	%	5.85	%		5.60	%		5.75	%
Expected return on plan assets		9.00	%		9.00	%		9.25	%	n/a			n/a			n/a
Rate of compensation increase		4.00	%		4.00	%		4.00	%	4.00	%		4.00	%		4.00	%
Health care cost trend rate		n/a			n/a			n/a		9.50	%		9.00	%		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			2012			2011

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. No contributions have been required since 1997, and the Company does not anticipate making contributions to the pension plan until after 2012.

Pension Plan Asset Allocations

The Company's pension plan asset allocation at December 31, 2007 and 2006 and the target allocation for 2008 are as follows:

	Target Allocation		Percentage of Plan Assets At December 31,
Asset Category	2008		2007		2006
Equity Securities		65%		71%		72%
Debt Securities		35%		29%		28%

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

In developing the expected long-term rate of return assumptions, management evaluates the pension plan's historical cumulative actual returns over several periods, all of which returns have been in excess of related broad indices. The expected long-term rate of return of 9.0% assumes an asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2008, the expected rate of return also will be 9.0%.

Share-Based Compensation

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

            SFAS 123 (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 projection achievement.

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

Under SFAS 123(R), compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $6.4 million were paid during 2006.  No such payments were made in 2007 or 2005.

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 $6.6 million for the year ended December 31, 2007, a reduction to compensation expense totaling $(6.5) million for the year ended December 31, 2006 and an increase to compensation expense totaling $3.6 million for the year ended December 31, 2005. Fair value adjustments resulted in capitalized compensation costs of $0.7 million during the year ended December 31, 2007, compared to a net credit to capitalized costs of $(0.8) million in 2006 and capitalized compensation costs of $0.4 million in 2005.

Equity Awards

A summary of activity related to nonqualified stock options follows:

	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2004		730,447		$	27.49
Exercised		(291,177	)		27.48
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

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, 2007, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 3.9 years.

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

The exercise of stock options during 2005-2007 was satisfied using a combination of original issue shares and open market purchases of the Company’s common stock. The Company realized $7.1 million, $1.5 million and $8.0 million in cash upon the exercise of options in the years ended December 31, 2007, 2006 and 2005, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $1.5 million, $0.3 million and $1.3 million were credited to additional paid in capital (common equity) in these periods.

The Company estimates that 100,000 common shares may be repurchased in 2008 upon the exercise of stock options.

4.      LONG-TERM DEBT

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

						December 31,
	Weighted-Average Interest Rate			Maturity Date		2007			2006
						Millions of dollars
Medium-Term Notes (unsecured)(a)		6.35	%		2008-2012	$	915		$	940
Senior Notes (unsecured) (b)		6.47	%		2034		40			-
First Mortgage Bonds (secured)		6.00	%		2009-2036		1,675			1,675
GENCO Notes (secured)		5.86	%		2011-2024		119			123
Industrial and Pollution Control Bonds		5.24	%		2012-2032		156			156
Senior Debentures(c)		7.43	%		2012-2026		116			119
Fair value of interest rate swaps(d)							17			21
Other					2008-2027		80			89
Total debt							3,118			3,123
Current maturities of long-term debt							(233	)		(43	)
Unamortized Discount							(6	)		(13	)
Total long-term debt, net						$	2,879		$	3,067

(a) Includes $100.0 million of variable interest debt in 2007 and 2006 and $25.0 million of fixed rate debt hedged by a variable interest rate swap in 2006.

(b) $40 million fixed rate notes are hedged by a variable interest rate swap.

(c) Includes $16.0 million of fixed rate debt hedged by a variable interest rate swap in 2007 compared to $19.2 million of such debt in 2006. 

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

The annual amounts of long-term debt maturities for the years 2008 through 2012 are summarized as follows:

Year	Millions of dollars
2008	$	233
2009		143
2010		23
2011		627
2012		273

On February 15, 2007 SCANA redeemed at maturity $25 million of its medium-term notes which bore interest at 6.9%.

On January 14, 2008 SCE&G issued $250 million First Mortgage Bonds having an annual interest rate of 6.05% and maturing on January 15, 2038.   The proceeds from the sale of these bonds will be used to repay short-term debt primarily incurred as a result of SCE&G’s construction program and for general corporate purposes.

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

5.      LINES OF CREDIT AND SHORT-TERM BORROWINGS

Details of lines of credit at December 31, 2007 and 2006, are as follows:

Millions of dollars	2007		2006
Lines of credit
Committed:
SCANA	$	200		$	200
SCE&G		400			400
Fuel Company		250			250
PSNC Energy		250			250
Long-term (total and available)	$	1,100		$	1,100
Uncommitted (a):
Total	$	78		$	103
Available for use		71			103
(a)  SCANA, SCE&G or a combination may use the $78 million line of credit.

Bank loans and commercial paper outstanding (270 or fewer days) at December 31, 2007 and 2006 were as follows:  

Millions of dollars	2007			2006
	Amount		Weighted Average Interest Rate	Amount		Weighted Average Interest Rate
SCANA	$	7	5.10%	$	-	-
SCE&G		323	5.75%		238	5.38%
Fuel Company		140	5.72%		124	5.38%
PSNC Energy		157	5.74%		125	5.40%
Total	$	627	5.73%	$	487	5.38%

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

Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or bank loans.  All such borrowings are supported by five-year revolving credit facilities which expire on December 19, 2011. SCANA also has a five-year revolving credit facility which expires December 19, 2011.  SCE&G, Fuel Company and PSNC Energy have commercial paper programs in the amounts of $350 million, $250 million and $250 million, respectively.

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, 2007, approximately $55 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 2007, 2006 and 2005 at an annual rate per share of $1.76, $1.68 and $1.56, respectively.

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

Millions of dollars	Cash Flow Hedging Activities			Minimum Pension Liability Adjustment			Deferred Costs of Employee Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Balance, December 31, 2004	$	(4	)	$	-		$	-		$	(4	)
Other comprehensive income (loss)		1			(1	)		-			-
Balance, December 31, 2005		(3	)		(1	)		-			(4	)
Other comprehensive income (loss)		(15	)		1			-			(14	)
Adoption of SFAS 158		-			-			(11	)		(11	)
Balance, December 31, 2006		(18	)		-			(11	)		(29	)
Other comprehensive income		7			-			-			7
Balance, December 31, 2007	$	(11	)	$	-		$	(11	)	$	(22	)

The Company recognized losses of $19.1 million and $27.6 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2007 and 2006, respectively.  As described in Notes 1 and 3, the Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other comprehensive income certain gains, losses, prior service costs and 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 2008 through 2012 is $2.4 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2007 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	583,176	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, 2007, 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 2007, 2006 and 2005 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, 2004		78,518			105,961			184,479		$	9.2
Shares Redeemed-$50 par value		(1,475	)		(6,600	)		(8,075	)		(0.4	)
Balance at December 31, 2005		77,043			99,361			176,404			8.8
Shares Redeemed-$50 par value		(2,608	)		(6,600	)		(9,208	)		(0.5	)
Balance at December 31, 2006		74,435			92,761			167,196			8.3
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

8.       INCOME TAXES

Total income tax expense (benefit) attributable to income (before cumulative effect of accounting change) for 2007, 2006 and 2005 is as follows:

Millions of dollars	2007			2006			2005
Current taxes:
Federal	$	101.3		$	93.9		$	10.2
State		12.7			9.8			11.1
Total current taxes		114.0			103.7			21.3
Deferred taxes, net:
Federal		23.4			11.7			1.7
State		3.5			5.3			(6.9	)
Total deferred taxes		26.9			17.0			(5.2	)
Investment tax credits:
Deferred-state		5.0			5.0			5.1
Amortization of amounts deferred-state		(2.6	)		(3.3	)		(1.9	)
Amortization of amounts deferred-federal		(3.0	)		(3.0	)		(3.1	)
Total investment tax credits		(0.6	)		(1.3	)		0.1
Synthetic fuel tax credits - federal		-			-			(134.2	)
Total income tax expense (benefit)	$	140.3		$	119.4		$	(118.0	)

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

Millions of dollars	2007			2006			2005
Income	$	320.0		$	304.0		$	319.5
Income tax expense (benefit)		140.3			119.4			(118.0	)
Preferred stock dividends		7.3			7.3			7.3
Total pre-tax income	$	467.6		$	430.7		$	208.8
Income taxes on above at statutory federal income tax rate	$	163.7		$	150.7		$	73.1
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		12.1			10.9			4.8
Synthetic fuel tax credits		(17.4	)		(33.5	)		(181.9	)
Deductible dividends-Stock Purchase Savings Plan		(6.9	)		(6.5	)		(5.9	)
Amortization of federal investment tax credits		(3.0	)		(3.0	)		(3.1	)
Non-taxable recovery of Lake Murray back-up dam project carrying costs		(2.0	)		(2.3	)		(3.8	)
Domestic production activities deduction		(3.9	)		(1.0	)		(1.4	)
Other differences, net		(2.3	)		4.1			0.2
Total income tax expense (benefit)	$	140.3		$	119.4		$	(118.0	)

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $934.8    million at December 31, 2007 and $913.0 million at December 31, 2006 are as follows:

Millions of dollars	2007		2006
Deferred tax assets:
Nondeductible reserves	$	103.3	$	103.8
Unamortized investment tax credits		51.9		58.9
Federal alternative minimum tax credit carryforward		-		22.1
Deferred compensation		18.9		29.0
Unbilled revenue		10.3		12.5
Monetization of bankruptcy claim		17.3		-
Other		33.2		38.6
Total deferred tax assets		234.9		264.9
Deferred tax liabilities:
Property, plant and equipment		977.2		966.8
Pension plan income		79.5		71.1
Deferred employee benefit plan costs		46.9		56.1
Deferred fuel costs		2.3		25.9
Other		63.8		58.0
Total deferred tax liabilities		1,169.7		1,177.9
Net deferred tax liability	$	934.8	$	913.0

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 2003 are closed for additional assessment.  With a few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2003.  The IRS has closed the examination of S. C. Coaltech No. 1, LP, a synthetic fuel partnership in which the Company has an interest, for the 2004 tax year, resulting in that return being accepted as filed.   The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed.

In connection with the initial adoption of FIN 48 effective January 1, 2007, the Company removed $15 million of previously recorded tax benefits from its balance sheet.  Because regulatory liabilities had been recorded for these previously recognized tax benefits under the provisions of SFAS 71, these benefits had never been recognized in the Company’s earnings or retained earnings.  As a result, the initial adoption of FIN 48 had no effect on the Company’s equity.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $15 million.  The Company anticipates that this unrecognized amount could change by the end of 2008, as it relates to litigation of a state issue which could be resolved by December 31, 2008.  Any change will be within the range of $0 to $15 million. Because any tax benefits recorded would be amortized into earnings over a number of years under SFAS 71, the impact on any individual year’s effective tax rate would be immaterial.  No material changes in the status of our tax positions have occurred subsequent to adoption.  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, 2007		$	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, 2007		$	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 or tax penalties in 2007, 2006 or 2005.

9.       FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2007 and 2006 were as follows:

	2007				2006
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,111.7	$	3,166.1	$	3,110.0	$	3,207.9
Preferred stock (subject to purchase or sinking funds)		7.9		7.0		8.3		7.8

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’s pension assets are invested in debt and equity securities that are accounted for as available-for-sale securities at fair value in accordance with SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities.”  SCANA also holds investments 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 independent parties.

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

Commodities

The Company uses derivative instruments to hedge forward purchases 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 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. PSNC Energy's tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized and unrealized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs.

The Company’s nonregulated gas operations recognize gains and losses as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period and record them in cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.  The Company estimates that most of the December 31, 2007 unrealized loss balance of $6.6 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 at current levels. As of December 31, 2007, all of the Company's cash flow hedges settle by their terms before the end of December 2010.

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain of its natural gas storage facilities.  At December 31, 2007, such counterparties held 44% of PSNC Energy’s natural gas inventory, with a carrying value of $40.1 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. These swaps provide for the Company to pay variable and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap and may replace it with a new swap also designated as a fair value hedge. At December 31, 2007 the estimated fair value of the Company's swaps totaled $0.6 million related to combined notional amounts of $16.0 million.

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.

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 December 2007 SCANA issued $40 million of the Floating Rate Senior Notes, and through a swap agreement has obtained a fixed rate of 6.47% on those notes.  The notes are to be issued at intervals between December 2008 and June 2009.   At December 31, 2007 the estimated fair value of the Company’s forward starting interest rate swap related to the Floating Rate Senior Notes totaled $7.2 million (loss).  

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.

10.     COMMITMENTS AND CONTINGENCIES

A.      Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 million of the liability per reactor would be assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $10 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $14.1 million.

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

B.      Environmental

SCE&G

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 sets 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 have challenged the rule, seeking a change in the method CAIR uses to allocate sulfur dioxide emission allowances.  The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements.  Although compliance plans and costs to comply with the rule have not been determined, it is believed that such costs will be material and will be recoverable through rates.

The EPA issued a final rule referred to as the Clean Air Mercury Rule (CAMR) in 2005 establishing a mercury emissions cap and trade program for coal-fired power plants that required limits to be met in two phases, in 2010 and 2018. 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 cannot predict the effect of this ruling on implementation of CAMR state implementation plans (SIPS) and newly promulgated CAMR regulations by the states.

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

SCE&G has been named, along with 29 others, by the EPA as a PRP at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  In 2008, SCE&G, along with other parties, reached a settlement with the EPA and the U.S. Department of Justice on this matter.  The settlement, which is subject to court approval, would result in an allocation of cost, net of insurance recoveries, to SCE&G that is not material, and such cost is expected to be recoverable through rates.

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). The deferral includes the estimated costs associated with the following matters.

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 $11.9 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 through rates.  At December 31, 2007, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $16.7 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 $4.6 million, which reflects its estimated remaining liability at December 31, 2007. PSNC Energy expects to recover through rates any costs, net of insurance recoveries, allocable to PSNC Energy arising from the remediation of these sites through rates.

C.      Franchise Agreements

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

D.     Claims and Litigation

In February 2008 the consumer affairs staff (the staff) of the Georgia Public Service Commission (GPSC) alleged to the GPSC that SCANA Energy Marketing, Inc. (SCANA Energy) and the state's largest natural gas marketer (the marketers) had overcharged certain of their respective customers.  The staff alleges that the marketers failed to inform customers with more expensive rate plans that a lower rate plan was available, charged customers in excess of the published price, and failed to give proper notice of a change in methodology for computing variable rates.  SCANA Energy believes it complied with all applicable rules and regulations, that none of its customers were treated unfairly, and that all requests it received from customers to be switched to a lower rate plan were honored. SCANA Energy has responded that these types of pricing plans exist in many deregulated markets, such as telecommunications, and are a natural development in a competitive environment. The GPSC has indicated that it may launch a formal investigation into the matter, and is expected to rule on the matter on March 4, 2008.  Separately, without admitting fault, the other marketer has offered to settle the matter before the GPSC by agreeing to improve communications and to pay $1 million to the Low Income Home Energy Assistance Program.  SCANA Energy is currently in discussions with the GPSC to settle the matter.  While the Company cannot determine 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.

On February 26, 2008, a purported class action was filed in U.S. District Court for the Northern District of Georgia, 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.  SCANA Energy has not been served with this lawsuit and has not yet had the opportunity to evaluate it.

In May 2004, SCANA and SCE&G were served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA 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 overruled 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 plaintiff appealed this ruling to the South Carolina Court of Appeals and the Court of Appeals has dismissed the appeal, determining that the Circuit Court ruling is not immediately appealable.  Plaintiff’s motion for class certification was recently heard and correspondence from the Circuit Court indicates the judge’s intention to certify the class.  There has been no formal order and the class remains limited to easements in Charleston County.  SCANA 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.

A complaint was filed in October 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The claim against SCE&G was settled by an agreement between the parties, and the settlement was approved in 2004 by South Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit. In addition, SCE&G filed a petition with the SCPSC in October 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G’s electric and gas service, to approve SCE&G’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

E.      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 $19.0 million, $15.0 million and $13.9 million in 2007, 2006 and 2005, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2008	$	16
2009		11
2010		2
2011		1
2012		1
Thereafter		5
Total	$	36

At December 31, 2007 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $3.7 million.

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 $2.3 billion, $2.4 billion and $2.2 billion in 2007, 2006 and 2005, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2008	$	1,729
2009		1,080
2010		640
2011		583
2012		546
Thereafter		3,261
Total	$	7,839

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.     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, 2007, the Company has recorded an ARO of approximately $99 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $208 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	2007			2006
Beginning balance	$	292		$	322
Liabilities incurred		1			1
Liabilities settled		(2	)		(2	)
Accretion expense		17			17
Revisions in estimated cash flows		(1	)		(46	)
Ending Balance	$	307		$	292

Revisions in estimated cash flows in 2006 primarily related to the expectation of lower cost escalations associated with decommissioning Summer Station than had been assumed in the prior cash flow analysis.

11.    SEGMENT OF BUSINESS INFORMATION

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

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

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

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

Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the Georgia Public Service Commission. Energy Marketing markets 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.

Disclosure of Reportable Segments (Millions of dollars)

2007	Electric Operations		Gas Distribution		Gas Transmission		Retail Gas Marketing		Energy Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
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	Electric Operations		Gas Distribution		Gas Transmission		Retail Gas Marketing		Energy Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	1,877	$	1,078	$	179	$	608	$	821	$	66		$	(66	)	$	4,563
Intersegment Revenue		9		-		322		-		128		306			(765	)		-
Operating Income		456		83		30		n/a		n/a		n/a			34			603
Interest Expense		15		24		7		2		-		-			161			209
Depreciation and Amortization		268		54		8		3		-		15			(15	)		333
Income Tax Expense		3		16		11		19		-		6			64			119
Net Income (Loss)		n/a		n/a		n/a		30		-		(11	)		291			310
Segment Assets		5,520		1,847		315		208		142		649			1,136			9,817
Expenditures for Assets		304		174		13		-		3		35			(2	)		527
Deferred Tax Assets		n/a		n/a		7		3		12		2			10			34

2005
Customer Revenue	$	1,909	$	1,168	$	237	$	664	$	799		$	70		$	(70	)	$	4,777
Intersegment Revenue		4		1		427		-		146			317			(895	)		-
Operating Income		299		75		26		n/a		n/a			n/a			36			436
Interest Expense		13		21		7		2		-			-			169			212
Depreciation and Amortization		450		49		8		3		-			13			(13	)		510
Income Tax Expense (Benefit)		4		18		8		14		(1	)		12			(173	)		(118	)
Net Income (Loss)		n/a		n/a		n/a		24		(1	)		(69	)		366			320
Segment Assets		5,531		1,701		427		284		128			553			895			9,519
Expenditures for Assets		280		122		5		-		1			18			(41	)		385
Deferred Tax Assets		n/a		n/a		6		8		3			2			7			26

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 (benefit) or assets other than utility plant to its segments. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. In accordance with SFAS 109, the Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

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

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

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

12.       QUARTERLY FINANCIAL DATA (UNAUDITED)

2007 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
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

2006 Millions of dollars, except per share amounts
Total operating revenues	$	1,389	$	944	$	1,062	$	1,168	$	4,563
Operating income		185		122		156		140		603
Income before cumulative effect of accounting change		92		58		89		65		304
Cumulative effect of accounting change, net of taxes (1)		6		-		-		-		6
Net income		98		58		89		65		310
Basic and diluted earnings per share		.85		.50		.76		.57		2.68

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

      See Note 3.

			Page
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		80
		Overview	80
		Results of Operations	81
		Liquidity and Capital Resources	85
		Environmental Matters	88
		Regulatory Matters	91
		Critical Accounting Policies and Estimates	91
		Other Matters	92
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		93
Item 8.	Financial Statements and Supplementary Data		95
		Report of Independent Registered Public Accounting Firm	95
		Consolidated Balance Sheets	96
		Consolidated Statements of Income	98
		Consolidated Statements of Cash Flows	99
		Consolidated Statements of Changes in Common Equity	100
		Notes to Consolidated Financial Statements	101

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

                OF OPERATIONS

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 for SCE&G over the next five years 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 controlling the 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, 2007 SCE&G provided electricity to 639,300 customers. 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%, with rates set at 10.7%. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

Legislative and regulatory initiatives, including the Energy Policy Act of 2005 (the “Energy Policy Act”) also could significantly impact the results of operations and cash flows for the electric operations segment. The Energy Policy Act became law in August 2005, and it provided, among other things, for the establishment of an electric reliability organization (ERO) to propose and enforce mandatory reliability standards for transmission systems and for procedures governing enforcement actions by the ERO and the Federal Energy Regulatory Commission (FERC). 

Consistent with reliability provisions of the Energy Policy Act, on July 20, 2006, FERC issued a final rule certifying the North American Electric Reliability Council (NERC) as the ERO.  On March 16, 2007, FERC issued a final rule establishing mandatory, enforceable reliability standards for the nation’s bulk power system. In the final rule, FERC approved 83 of the 107 mandatory reliability standards submitted by the NERC and compliance with these standards became mandatory on June 18, 2007. FERC has subsequently approved 8 critical infrastructure protection standards which are mandatory and enforceable.  The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities.

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

Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and is primarily engaged in the purchase and sale of natural gas to retail customers in portions of South Carolina. At December 31, 2007 this segment provided natural gas to approximately 302,500 customers.

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. This allowed return on equity is 10.25%.

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 2007 or in 2006, 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.

Net Income

Net income was as follows:

Millions of dollars	2007		% Change			2006		% Change			2005
Net income	$	245.1		4.5	%	$	234.6		(9.1	)%	$	258.1

• 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, increased incentive compensation and other benefits of $8.8 million and increased depreciation expense of $7.0 million.

• 2006 vs 2005 Net income decreased primarily due to lower electric margin of $7.8 million, increased generation, transmission and distribution expenses of $8.8 million, a settlement related to power marketing practices of $8.7 million, lower pension income and other postretirement benefits of $2.8 million, increased customer service expenses of $1.2 million and increased property taxes of $3.7 million. These increases were partially offset by higher gas margins of $10.5 million and lower incentive compensation expense of $8.6 million.

Pension Income

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

Millions of dollars	2007		2006		2005
Income Statement Impact:
Reduction in employee benefit costs	$	4.3	$	2.4	$	5.6
Other income		14.0		12.7		12.2
Balance Sheet Impact:
Reduction in capital expenditures		1.3		0.7		1.6
Component of amount due to Summer Station co-owner		0.4		0.2		0.6
Total Pension Income	$	20.0	$	16.0	$	20.0

For the last several years, the market value of SCE&G’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Among the reasons income in 2007 was higher than income in 2006 was favorable asset investment experience. Among the reasons 2006’s income was lower than 2005’s was a reduction of the assumed rate of return on plan assets from 9.25% to 9%.  See also the discussion of pension accounting in Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 3.8% of income before income taxes in 2007, 2.2% in 2006 and 1.5% in 2005.

Dividends Declared

SCE&G’s Board of Directors has declared the following dividends on common stock held by SCANA during 2007:

Declaration Date	Dividend Amount	Quarter Ended	Payment Date
February 15, 2007	$36.0 million	March 31, 2007	April 1, 2007
April 26, 2007	$39.7 million	June 30, 2007	July 1, 2007
August 2, 2007	$39.7 million	September 30, 2007	October 1, 2007
October 24, 2007	$35.0 million	December 31, 2007	January 1, 2008

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	2007		% Change			2006		% Change			2005
Operating revenues	$	1,961.7		4.0	%	$	1,886.6		(1.3	)%	$	1,912.0
Less: Fuel used in generation		662.3		7.7	%		615.1		(0.5	)%		618.1
Purchased power		32.7		18.9	%		27.5		(26.1	)%		37.2
Margin	$	1,266.7		1.8	%	$	1,244.0		(1.0	)%	$	1,256.7

• 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.

• 2006 vs 2005 Margin decreased by $20.8 million due to unfavorable weather, by $16.0 million due to decreased off-system sales and by $6.5 million due to lower industrial sales. These decreases were offset by residential and commercial customer growth of $26.5 million and increased other electric revenue of $4.1 million. Purchased power cost decreased due to lower volumes.

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

Classification (in thousands)	2007		% Change			2006		% Change			2005
Residential		7,814		2.8	%		7,598		(0.5	)%		7,634
Commercial		7,472		2.8	%		7,268		1.9	%		7,135
Industrial		6,267		1.4	%		6,183		(6.0	)%		6,581
Sales for resale (excluding interchange)		2,100		1.2	%		2,076		(5.5	)%		2,197
Other		563		6.8	%		527		0.8	%		523
Total territorial		24,216		2.4	%		23,652		(1.7	)%		24,070
Negotiated Market Sales Tariff (NMST)		672		(24.2	)%		886		(29.3	)%		1,253
Total		24,888		1.4	%		24,538		(3.1	)%		25,323

• 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.

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

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	2007		% Change			2006		% Change			2005
Operating revenues	$	519.1		2.9	%	$	504.6		(0.8	)%	$	508.8
Less: Gas purchased for resale		386.7		(2.2	)%		395.5		(5.1	)%		416.6
Margin	$	132.4		21.4	%	$	109.1		18.3	%	$	92.2

• 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.

• 2006 vs 2005 Margin increased by $17.5 million due to increased retail gas base rates which became effective with the first billing cycle in November 2005 and by $4.0 million due to an SCPSC approved increase in retail gas base rates effective with the first billing cycle in November 2006. These increases were offset by $4.0 million due to lower firm margin resulting from customer conservation.

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

Classification (in thousands)	2007		% Change		2006	% Change		2005
Residential	$	11,014	0.8	%	10,926	(14.7	)%	12,806
Commercial		12,270	2.4	%	11,984	(4.5	)%	12,552
Industrial		18,126	1.4	%	17,879	12.4	%	15,907
Transportation gas		2,811	13.2	%	2,484	22.2	%	2,032
Total	$	44,221	2.2	%	43,273	(0.1	)%	43,297

• 2007 vs 2006 Residential, commercial and transportation gas sales volumes increased primarily due to customer growth.

• 2006 vs 2005 Residential and commercial sales volumes decreased primarily due to milder weather and conservation. Industrial and transportation sales volumes increased due to the competitive position of gas relative to alternate fuel sources.

Other Operating Expenses

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

Millions of dollars	2007		% Change			2006		% Change			2005
Other operation and maintenance	$	477.9		3.7	%	$	460.7		4.4	%	$	441.2
Depreciation and amortization		276.4		(3.3	)%		285.8		(38.5	)%		464.8
Other taxes		146.9		6.6	%		137.8		5.2	%		131.0
Total	$	901.2		1.9	%	$	884.3		(14.7	)%	$	1,037.0

• 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 expenses 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 net property additions.  Other taxes increased primarily due to higher property taxes.

• 2006 vs 2005 Other operation and maintenance expenses increased by $14.2 million primarily due to increased generation, transmission and distribution expenses, by $4.6 million due to lower pension income and other postretirement benefits and by $2.0 million due to higher customer service expenses. These increases were partially offset by $13.9 million due to decreased incentive compensation expense. Depreciation and amortization expense decreased by $185.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2006 compared to 2005 (see Income Taxes -Recognition of Synthetic Fuel Tax Credits), partially offset by $6.7 million due to property additions and higher depreciation rates. 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	2007			% Change			2006			% Change			2005
Gain on sale of assets	$	4.5			50.0	%	$	3.0			76.5	%	$	1.7
Other revenues		28.8			(52.6	)%		60.8			(62.6	)%		162.4
Other expenses		(11.1	)		(75.4	)%		(45.1	)		(67.9	)%		(140.7	)
Total	$	22.2			18.7	%	$	18.7			(20.1	)%	$	23.4

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

 • 2006 vs 2005  Other revenues decreased $91.5 million due to lower power marketing activities, $10.8 million due to the termination of a contract to operate a steam combustion turbine at the United States Department of Energy (DOE) Savannah River Site and by $4.3 million due to lower carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project as discussed at Income Taxes - Recognition of Synthetic Fuel Tax Credits below. These decreases were partially offset by higher interest income of $8.7 million and higher third-party coal sales revenue of $4.8 million.   Other expenses decreased by $90.6 million due to lower power marketing activities and $4.4 million due to the termination of the DOE’s Savannah River Site contract. These decreases were partially offset by increased charges of $8.7 million related to the settlement of the FERC power marketing matter and higher expenses to support third-party coal sales of $3.6 million.

Interest Expense

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

Millions of dollars	2007		% Change			2006		% Change			2005
Interest on long-term debt, net	$	109.6		(11.5	)%	$	123.9		(7.1	)%	$	133.3
Other interest expense		31.2		93.8	%		16.1		46.4	%		11.0
Total	$	140.8		0.6	%	$	140.0		(3.0	)%	$	144.3

• 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.

• 2006 vs 2005 Interest on long-term debt decreased primarily due to lower interest rates and the redemption of outstanding debt in 2005. 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 during 2007 compared to $33.5 million during 2006 and due to other changes in operating income. 

Recognition of Synthetic Fuel Tax Credits

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. Under an accounting methodology approved by the SCPSC in a January 2005 order, construction costs related to the Lake Murray back-up dam project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.  The synthetic fuel tax credit program expired at the end of 2007.

The level of depreciation expense and related tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account declines as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement.  In addition, SCE&G records non-cash carrying costs on the unrecovered investment.  The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2007 and 2006 are as follows:

Millions of dollars		2007		2006			2005
Depreciation and amortization expense	$	(8.4	)	$	(28.2	)	$	(214.0	)
Income tax benefits:
From synthetic fuel tax credits		16.7			30.0			179.0
From accelerated depreciation		3.2			10.8			81.8
From partnership losses		7.0			7.8			28.9
Total income tax benefits		26.9			48.6			289.7
Losses from Equity Method Investments		(18.5	)		(20.4	)		(75.7	)
Impact on Net Income		-			-			-

The 2007 amounts are estimates based on preliminary benchmark information and reflect the likelihood that credits available in 2007 will be phased down pursuant to regulations which limit the credits based on the relative commodity price of crude oil.  Amounts in 2005 reflect the recognition of previously deferred tax credits.  See discussion below.

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

The benchmark price range for 2006 resulted in a phase-out of 33% for 2006. SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2007 also are likely to be impacted by the phase-out calculation. As such, in 2007 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 32.7% of credits generated in 2007 will be available (phase-out of 67.3%).  The U. S. Government is expected to publish the benchmark price range for 2007 in the second quarter of 2008, after which the Company will finalize its estimate of available credits.

The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation.  To the extent that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs will likely be sought. As of December 31, 2007, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $68.4 million.  The Company expects these costs to be recoverable through rates.

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, 2007 was 3.40.  The Company’s ratio of earnings to combined fixed charges and preference dividends for the same period was 3.17.

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, if requested.

SCE&G expects to add additional base load electric generation in the 2015 to 2016 timeframe.  Based on an evaluation of alternatives, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) have selected the Summer Station site as the preferred site if new nuclear generation is built. Due to the significant lead time required for construction of nuclear generation, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) that would cover two new nuclear units. The COL application, if submitted, would be reviewed by the NRC for an estimated three years. SCE&G is uncertain if or when a COL would be submitted to the NRC.  While SCE&G’s current plans are to pursue the development of one or both of these nuclear units, these plans will continue to be influenced by many factors, including NRC licensing attainment, ongoing evaluation of relative construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

In May 2007, the Base Load Review Act (the Act) became law in South Carolina.  This law is intended to allow a utility to recover prudently incurred capital and operating costs associated with new nuclear or coal-fired base load electric generating facilities larger than 350 megawatts.  Based on an application filed by the utility under the Act, the SCPSC would review and rule on the prudency of the decision to build the plant.  If the decision was found to be prudent, that finding would be binding on all future proceedings so long as the plant is constructed in accordance with the schedules, estimates and projections set forth in the approved application.  In addition, beginning with the initial proceeding, the utility would 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 the utility’s updated cost of debt and capital structure.  The cost of service and rate design would be based on the rates approved in the utility’s most recent electric rate order.  The utility may choose to file for a project-specific return on common equity or use the return from its most recent rate proceeding if the proceeding is less than five years old.

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 2008-2010, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars	2008		2009		2010
SCE&G:
Electric Plant:
Generation (including GENCO)	$	481	$	351	$	652
Transmission		47		60		52
Distribution		171		168		172
Other		40		41		19
Nuclear Fuel		6		27		74
Gas		65		61		67
Common and Other		13		11		7
Total	$	823	$	719	$	1,043

The Company’s contractual cash obligations as of December 31, 2007 are summarized as follows:

Contractual Cash Obligations

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)	$	4,533	$	595	$	639	$	357	$	2,942
Capital leases		2		1		1		-		-
Operating leases		24		14		10		-		-
Purchase obligations		316		293		22		1		-
Other commercial commitments		872		511		258		28		75
Total	$	5,747	$	1,414	$	930	$	386	$	3,017

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

Included in purchase obligations are customary purchase orders under which 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, and no further contributions are anticipated until after 2010. The Company’s cash payments under the health care and life insurance benefit plan were $8.7 million in 2007, and such annual payments are expected to increase to the $10-$11 million range in the future.

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, the incurrence of additional short- and long-term indebtedness 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 2007 (actual) and 2008 (estimated) for certain expenditures are as follows:

Millions of dollars		2007		2008
Property additions and construction expenditures, including nuclear fuel, net of AFC	$	619	$	818
Investments		19		-
Total	$	638	$	818

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.

Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC authority to issue short-term debt.  The FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 6, 2010.

At December 31, 2007, SCE&G and Fuel Company had available the following lines of credit and short-term borrowings outstanding:

	Millions of dollars
Lines of credit:
SCE&G and Fuel Company
Committed long-term (total and available, expire December 2011)	$	650
Uncommitted (a):
Total		78
Used by SCANA		7
Available for use		71
Short-term borrowings outstanding:
Commercial paper (270 or fewer days)	$	463.6
Weighted average interest rate		5.74	%

(a) Line of credit that either SCE&G, SCANA or a combination may use.

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 currently outstanding First Mortgage Bonds and all of its future mortgage-backed debt (Bonds) has been and will be issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, 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, 2007, the Bond Ratio was 7.08.

SCE&G’s Restated Articles of Incorporation (Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders unless net earnings (as therein defined) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times (1.5) 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, 2007, the Preferred Stock Ratio was 2.08.

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, 2007, the Ten Percent Test would have limited total issuances of unsecured indebtedness to approximately $445.4 million. Unsecured indebtedness at December 31, 2007, totaled $436.3 million, and was comprised primarily of short-term borrowings.

Financing Cash Flows

During 2007 the Company experienced net cash inflows related to financing activities of approximately $72 million primarily from capital contributions from parent.

In anticipation of the issuance of debt, the Company may use interest rate lock or similar 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.

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 Bonds.  The loss of approximately $14 million on the settlement of these swaps will be amortized over the 30-year life of the Bonds.

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

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 Air Mercury Rule (CAMR), 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, 2007, the Company’s capital expenditures for environmental control totaled $261.1 million. These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $34.0 million during 2007, $28.1 million during 2006, and $25.2 million during 2005.  It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $280.2 million for 2008 and $306.6 million for the four-year period 2009-2012. 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 primary 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 renewable portfolio standard (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.

At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2007.  The Company cannot predict whether such legislation will be introduced or passed in South Carolina in 2008, 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 sets 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 have challenged the rule seeking a change in the method CAIR uses to allocate sulfur dioxide emission allowances. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements.  Although compliance plans and costs to comply with the rule have not been determined, it is believed that such costs will be material and will be recoverable through rates.

The EPA issued a final rule referred to as CAMR in 2005 establishing a mercury emissions cap and trade program for coal-fired power plants that required limits to be met in two phases, in 2010 and 2018. 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 cannot predict the effect of this ruling on implementation of CAMR state implementation plans (SIPS) and newly promulgated CAMR regulations by the states.

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’s compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet CAIR regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $450 million over the 2007-2010 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $2.4 million in 2010 and $16 million in 2011 and each year thereafter. To meet compliance requirements for the years 2012-2016, SCE&G and GENCO anticipate additional capital expenditures totaling approximately $480 million.

Water Quality

The Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the Clean Water Act, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all, and renewed for nearly all, of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the Clean Water Act. Such legislation may include limitations to 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 DOE in 1983.  As of December 31, 2007, 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.

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 on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. 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 site has not been remediated nor has a cleanup cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G has been named, along with 29 others, by the EPA as a PRP at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from approximately 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  In 2008, SCE&G, along with other parties, reached a settlement with the EPA and the U.S. Department of Justice on this matter.  The settlement, which is subject to court approval, would result in an allocation of cost, net of insurance recoveries, to SCE&G that is not material, and such cost 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 $11.9 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 through rates.  At December 31, 2007, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $16.7 million at December 31, 2007.

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

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.

In May 2007, the 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.

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.

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 1 to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2007, the Company’s net investments in fossil/hydro and nuclear generation assets were $2.3 billion and $517 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 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, 2007 and 2006, accounts receivable included unbilled revenues of $92.8 million and $91.7 million, respectively, compared to total revenues of $2.5 billion for 2007 and $2.4 billion for 2006.

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).

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.

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, 2007, the Company has recorded an ARO of approximately $99 million for nuclear plant decommissioning (as discussed above) and an ARO of $195 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.

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.

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, 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

	Expected Maturity Date
December 31, 2006 Millions of dollars	2007	2008	2009	2010	2011	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	3.7	3.7	103.7	10.4	164.9	1,667.9	1,954.3	2,001.2
Average Interest Rate (%)	7.78	7.78	6.18	6.31	6.70	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 $72 million at December 31, 2007 and $80 million at December 31, 2006, which amounts do not have stated interest rates associated with them.

In the fourth quarter 2007 SCE&G entered into several 30-year forward starting swap agreements in anticipation of its proposed issuance of $250 million in debt no later than February 29, 2008.  At December 31, 2007 the estimated fair value of these swaps totaled $6.3 million (loss).  On January 14, 2008 SCE&G issued $250 million of its First Mortgage Bonds having an annual interest rate of 6.05% and maturing on January 15, 2038.  SCE&G terminated the forward starting interest rate swaps concurrent with the issuance of the debt.  This debt and related swaps are not reflected in the table above.

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
Futures Contracts - Long	2008	2009
Settlement Price (a)	8.08	8.72
Contract Amount (b)	13.1	16.4
Fair Value (b)	12.2	15.9

	Expected Maturity
Commodity Swaps	2008	2009
Pay fixed/receive variable (b)	68.6	24.9
Average pay rate (a)	8.5696	8.8257
Average received rate (a)	7.8498	8.6754
Fair value (b)	62.9	24.5
(a) Weighted average, in dollars
(b) Millions of dollars

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

The 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 recorded as a regulatory asset or liability.

 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, 2007 and 2006, and the related consolidated statements of income, changes in common equity, and of cash flows for each of the three years in the period ended December 31, 2007. 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2007 and 2006 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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.

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

/s/Deloitte & Touche LLP

Columbia, South Carolina

February 29, 2008

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2007			2006
Assets
Utility Plant In Service:	$	8,380		$	7,876
Accumulated Depreciation and Amortization		(2,643	)		(2,483	)
		5,737			5,393
Construction Work in Progress		383			316
Nuclear Fuel, Net of Accumulated Amortization		82			39
Utility Plant, Net		6,202			5,748
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		38			31
Assets held in trust, net-nuclear decommissioning		62			56
Other investments		-			25
Nonutility Property and Investments, Net		100			112
Current Assets:
Cash and cash equivalents		41			24
Receivables, net of allowance for uncollectible accounts of $2 and $5		320			311
Receivables-affiliated companies		29			41
Inventories (at average cost):
Fuel		139			147
Materials and supplies		97			85
Emission allowances		33			22
Prepayments and other		52			20
Deferred income taxes		5			19
Total Current Assets		716			669
Deferred Debits and Other Assets:
Due from parent – pension asset, net		228			200
Due from other affiliates		-			41
Emission allowances		-			27
Regulatory assets		629			702
Other		102			127
Total Deferred Debits and Other Assets		959			1,097
Total	$	7,977		$	7,626

December 31, (Millions of dollars)	2007		2006
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,622	$	2,457
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,728		2,563
Preferred Stock, net (Subject to purchase or sinking funds)		7		8
Long-Term Debt, net		2,003		2,008
Total Capitalization		4,738		4,579
Minority Interest		89		86
Current Liabilities:
Short-term borrowings		464		362
Current portion of long-term debt		13		14
Accounts payable		175		155
Accounts payable-affiliated companies		178		147
Customer deposits and customer prepayments		42		40
Taxes accrued		116		112
Interest accrued		33		33
Dividends declared		37		23
Other		46		63
Total Current Liabilities		1,104		949
Deferred Credits and Other Liabilities:
Deferred income taxes, net		820		807
Deferred investment tax credits		103		118
Asset retirement obligations		294		279
Due to parent - postretirement and other benefits		187		194
Due to other affiliate		-		6
Regulatory liabilities		609		541
Other		33		67
Total Deferred Credits and Other Liabilities		2,046		2,012
Commitments and Contingencies (Note 10)		-		-
Total	$	7,977	$	7,626

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, (Millions of dollars)	2007			2006			2005
Operating Revenues:
Electric	$	1,962		$	1,886		$	1,912
Gas		519			505			509
Total Operating Revenues		2,481			2,391			2,421
Operating Expenses:
Fuel used in electric generation		662			615			618
Purchased power		33			27			37
Gas purchased for resale		387			396			417
Other operation and maintenance		478			461			441
Depreciation and amortization		276			286			465
Other taxes		147			138			131
Total Operating Expenses		1,983			1,923			2,109
Operating Income		498			468			312
Other Income (Expense):
Other income		29			61			163
Other expenses		(11	)		(45	)		(140	)
Gains on sale of investments and assets		4			3			-
Interest charges, net of allowance for borrowed funds used during construction of $13, $8 and $3		(141	)		(140	)		(144	)
Allowance for equity funds used during construction		2			-			-
Total Other Expense		(117	)		(121	)		(121	)
Income Before Income Taxes (Benefit), Losses from Equity Method Investments, Minority
Interest, Cumulative Effect of Accounting Change and Preferred Stock Dividends		381			347			191
Income Tax Expense (Benefit)		109			88			(150	)
Income Before Losses from Equity Method Investments, Minority Interest,
Cumulative Effect of Accounting Change and Preferred Stock Dividends		272			259			341
Losses from Equity Method Investments		(20	)		(22	)		(77	)
Minority Interest		7			7			6
Cumulative Effect of Accounting Change, net of taxes		-			4			-
Net Income		245			234			258
Preferred Stock Cash Dividends		7			7			7
Earnings Available for Common Shareholder	$	238		$	227		$	251

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2007			2006			2005
Cash Flows From Operating Activities:
Net income	$	245		$	234		$	258
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		-			(4	)		-
Losses from equity method investments		20			22			77
Minority interest		7			7			6
Depreciation and amortization		276			286			465
Amortization of nuclear fuel		19			17			18
Gain on sale of assets		(4	)		(3)			(1	)
Allowance for equity funds used during construction		(2	)		-			-
Carrying cost recovery		(6	)		(7	)		(11	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		(51	)		49			(87	)
Inventories		(43	)		(146	)		(119	)
Prepayments		(32	)		(8)			18
Due from parent - pension asset		(27	)		(13	)		(17	)
Regulatory assets		17			(10	)		(30	)
Deferred income taxes, net		27			14			19
Other regulatory liabilities		53			9			(165	)
Due to parent - postretirement benefits		8			(3	)		6
Accounts payable		38			(16	)		6
Taxes accrued		4			(28	)		(12	)
Interest accrued		-			(2	)		-
Changes in fuel adjustment clauses		5			32			(32	)
Changes in other assets		45			19			(13	)
Changes in other liabilities		(59	)		25			24
Net Cash Provided From Operating Activities		540			474			410
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(613	)		(409	)		(330	)
Nonutility property additions		(6	)		(3	)		(1	)
Proceeds from sales of assets		5			3			2
Investments		19			(22	)		(18	)
Net Cash Used For Investing Activities		(595	)		(431	)		(347	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		-			132			121
Contribution from parent		76			9			95
Repayment of debt		(6	)		(151	)		(264	)
Redemption of preferred stock		(1	)		-			(1	)
Dividends		(143	)		(162	)		(158	)
Short-term borrowings - affiliate, net		44			75			(7	)
Short-term borrowings, net		102			59			150
Net Cash Provided From (Used For) Financing Activities		72			(38	)		(64	)
Net Increase (Decrease) in Cash and Cash Equivalents		17			5			(1	)
Cash and Cash Equivalents, January 1		24			19			20
Cash and Cash Equivalents, December 31	$	41		$	24		$	19
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $13, $8 and $3)	$	104		$	122		$	140
- Income taxes		70			93			26
Noncash Investing and Financing Activities:
Accrued construction expenditures		58			43			29

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY

										Accumulated
					Other					Other				Total
	Common Stock (a)				Paid In		Retained			Comprehensive				Common
	Shares		Amount		Capital		Earnings			Income (Loss)				Equity
	(Millions)
Balance at December 31, 2004		40	$	571	$	674	$	919					$		2,164
Capital Contributions From Parent						95									95
Earnings Available for Common Shareholder								251							251
Cash Dividends Declared								(148	)						(148	)
Balance at December 31, 2005		40		571		769		1,022							2,362
Capital Contributions From Parent						9									9
Earnings Available for Common Shareholder								227							227
Deferred Cost of Employee Benefit Plans,
net of taxes $(4)										$	(7	)			(7	)
Cash Dividends Declared								(134	)						(134	)
Balance at December 31, 2006		40		571		778		1,115			(7	)			2,457
Capital Contributions From Parent						76									76
Earnings Available for Common Shareholder								238							238
Deferred Cost of Employee Benefit Plans,
net of taxes $(1)											(1	)			(1	)
Cash Dividends Declared								(148	)						(148	)
Balance at December 31, 2007		40	$	571	$	854	$	1,205		$	(8	)	$		2,622

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

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

See Notes to Consolidated Financial Statements.

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 $315 million) serves as collateral for its long-term borrowings.

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	2007		2006
Regulatory Assets:
Accumulated deferred income taxes	$	156	$	169
Under-collections-electric fuel and gas cost adjustment clauses		-		49
Environmental remediation costs		17		18
Asset retirement obligations and related funding		264		254
Franchise agreements		52		55
Deferred regional transmission organization costs		5		8
Deferred employee benefit plan costs		109		128
Other		26		21
Total Regulatory Assets	$	629	$	702

Regulatory Liabilities:
Accumulated deferred income taxes	$	32	$	34
Over-collections – electric fuel and gas cost adjustment clauses		19		-
Other asset removal costs		472		438
Storm damage reserve		49		44
Planned major maintenance		15		6
Other		22		19
Total Regulatory Liabilities	$	609	$	541

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

Under- and over-collections-electric fuel and gas cost adjustment clauses, net, represent amounts under- or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings. Included in these amounts are regulatory assets or liabilities arising from realized and unrealized gains and losses incurred in the natural gas hedging programs of the Company’s regulated operations.  In addition, certain reagents used to treat fuel emission are included.  See Notes 1E and 1L.

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.

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 an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

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

Deferred employee benefit plan costs represent amountsof 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.)

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 and certain transmission and distribution insurance premiums.  In 2007, $1.4 million was drawn from the reserve. No significant amounts were drawn in 2006.  (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 is allowed to collect $8.5 million annually over an eight-year period, beginning in January 2005, through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle and are a component of cost of service.

The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets.  Other regulatory assets represent costs which have not been approved for recovery by the SCPSC. 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 is subject to SCPSC 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 the Company’s portion of Summer Station was approximately $1.0 billion as of December 31, 2007 and 2006 (including amounts related to ARO). Accumulated depreciation associated with SCE&G’s share of Summer Station was $513.1 million and $496.8 million as of December 31, 2007 and 2006, 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 $86.7 million in 2007, $77.5 million in 2006 and $76.3 million in 2005.

Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, SCE&G is collecting $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2007, the Company incurred $11.6 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 October 2006 and is accruing $1.1 million per month for its portion of the outage scheduled for the spring of 2008. Total costs for the 2006 outage were $25.8 million, of which the Company was responsible for $17.2 million. As of December 31, 2007 and 2006, the Company had an accrued balance of $12.7 million and $0.2 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 5.8% for 2007, 5.0% for 2006 and 3.2% for 2005. 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 $92.8 million and $91.7 million as of December 31, 2007 and 2006, respectively.

 Fuel costs 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. The Company had overcollected through the electric fuel cost component $11.4 million at December 31, 2007 which amount is included in other regulatory liabilities.   The Company had undercollected $28.9 million at December 31, 2006 which amount is included in other regulatory assets.

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the 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. At December 31, 2007 the Company had overcollected $7.5 million which amount is also included in other regulatory liabilities.  At December 31, 2006 the Company had undercollected $20.3 million which amount is also included in other regulatory assets.

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 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     3.13% in 2007, 3.15% in 2006 and 3.16% in 2005. These rates reflect higher depreciation rates approved by the SCPSC in connection with electric and gas rate cases effective January 2005 and November 2005, respectively.

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.

Under the Company’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2007, 2006 and 2005) 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 $8.6 million in 2007 and $10.1 million in 2006.

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

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

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

J.       Environmental

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

K.      Cash and Cash Equivalents

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

L.      Commodity Derivatives

The Company 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

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

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

SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. 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 is not expected to have an impact on the Company’s results of operations, cash flows or financial position.

SFAS 157, “Fair Value Measurements,” was issued in September 2006.  SFAS 157 establishes a framework for measuring fair value to increase the consistency and comparability in fair value measurements.  The Company will adopt SFAS 157 in the first quarter of 2008, and has determined that the adoption will not have a material impact on the Company’s results of operations, cash flows or financial position.  The Company believes it will likely be required to provide additional disclosures as part of future financial statements, beginning with first quarter 2008.

FIN 48, “Accounting for Uncertainty in Income Taxes,” prescribes the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes financial statement recognition threshold and measurement attributes for tax positions taken or expected to be taken in tax returns. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted FIN 48 in the first quarter of 2007.  (See Note 8).

FASB Staff Position (FSP) AUG AIR-1 “Accounting for Planned Major Maintenance Activities,” amended APB 28, “Interim Financial Reporting,” to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance.  As disclosed in Note 1A, the Company has received specific SCPSC orders providing for use of accrue-in-advance accounting for certain planned major maintenance activities. Accordingly, the Company will continue to follow accrue-in-advance accounting as allowed under SFAS 71 for these activities. The Company’s adoption of FSP AUG AIR-1 in the first quarter of 2007 had no impact on the Company’s results of operations, cash flows or financial position.

N.      Affiliated Transactions

Carolina Gas Transmission Corporation (CGTC) (formerly South Carolina Pipeline Corporation (SCPC)) 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 $1.5 million and $1.9 million payable to CGTC for transportation services at December 31, 2007 and 2006, respectively.

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.

Total interest income, based on market interest rates, associated with the Company’s advances to affiliated companies in 2007, 2006 and 2005 was not significant.

 The Company purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating Station and to serve its retail gas customers. Such purchases totaled approximately $208.9 million in 2007, $114.5 million in 2006 and $128.5 million in 2005. SCE&G’s payables to SEMI for such purposes were $12.0 million and $14.0 million as of December 31, 2007 and 2006, respectively.

The Company holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. The Company’s receivables from these affiliated companies were $28.8 million and $31.8 million at December 31, 2007 and 2006, respectively. The Company’s payables to these affiliated companies were $26.9 million and $26.6 million at December 31, 2007 and 2006, respectively. The Company purchased synthetic fuel from these affiliated companies of $281.6 million in 2007, $291.1 million in 2006 and $248.1 million in 2005. The Company made cash investments in these affiliated companies of $16.2 million in 2007, $18.4 million in 2006 and $17.7 million in 2005.  SCE&G’s investment in the two partnerships will be liquidated in 2008 as a result of the expiration of the synthetic fuel tax credits program at the end of 2007.

SCE&G purchases shaft horsepower from a cogeneration facility.  The facility is owned by a limited liability company (LLC) in which SCANA holds an equity method investment.  SCE&G’s payables to the LLC were $2.1 million and $2.5 million at December 31, 2007 and 2006, respectively.  SCE&G purchased shaft horsepower from the LLC of $27.7 million in 2007, $27.0 million in 2006 and $24.0 million in 2005.

Summarized combined financial information of unconsolidated affiliates as of and for the years ended December 31, 2007, 2006 and 2005, is presented below:

		2007			2006			2005
		Millions of dollars
Current assets	$	42		$	49		$	46
Non-current assets		1			5			8
Current Liabilities		51			42			39
Non-current liabilities		(8	)		12			15
Revenues		336			379			298
Gross profit		37			62			4
Loss before income tax benefit		(82	)		(67	)		(62	)

O.      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.

P.      Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, comprised of the deferred cost of employee benefit plans, totaled $7.9 million and $6.9 million as of December 31, 2007 and 2006, respectively.

2.      RATE AND OTHER REGULATORY MATTERS

Electric

In December 2007 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 agreed rate increase produces a 10.7% return).  The new rates became effective January 1, 2008.

In the December 2007 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 was recognized in 2007, 2006 or 2005.

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.

In May 2007, the 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.

In January 2005 the SCPSC approved SCE&G’s application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray back-up dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits. The Company expects these costs to be recoverable through rates.

Gas

In October 2007 the SCPSC approved an increase in retail natural gas rates of 0.9% under the terms of the Natural Gas Rate Stabilization Act (Stabilization Act).  The Stabilization Act is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas service infrastructure.  The rate adjustment was effective with the first billing cycle in November 2007.

SCE&G's gas rates are calculated using a methodology approved by the SCPSC in October 2006 which authorized SCE&G to adjust its cost of gas on a monthly, rather than an annual, basis beginning in December 2006.   The cost of gas adjustment is based on a twelve-month rolling average.

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

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, 2007, 2006 and 2005, the Company’s net periodic benefit income for the pension plan was $20.0 million, $16.0 million and $20.0 million, respectively, for the pension plan and net periodic benefit cost was $12.8 million, $14.3 million and $12.2 million, respectively, for the postretirement plan.

Share-Based Compensation

The Company participates in the SCANA Long-Term Equity Compensation Plan which provides for grants of incentive nonqualified stock options, stock appreciation rights, restricted stock, performance shares and performance units to certain key employees and non-employee directors. The plan currently authorizes the issuance of up to five million shares of 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.

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 projection achievement.

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

Under SFAS 123(R), compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $1.2 million were paid during 2006.  No such payments were made in 2007 or 2005.

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 $3.8 million for the year ended December 31, 2007, a reduction to compensation expense totaling $(4.8) million for the year ended December 31, 2006 and an increase to compensation expense totaling $2.3 million for the year ended December 31, 2005.  Fair value adjustments resulted in capitalized compensation costs of $0.7 million during the year ended December 31, 2007, a net credit to capitalized  compensation costs of $(0.7) million in 2006 and capitalized compensation costs of $0.3 million in 2005.

Equity Awards

A summary of activity related to nonqualified stock options follows:

	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2004		730,447		$	27.49
Exercised		(291,177	)		27.48
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

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, 2007, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 3.9 years.

All options were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense was recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123(R), pro forma earnings available for the common shareholder for the year ended December 31, 2005 would have been $0.2 million lower than as reported.

The exercise of stock options during 2005-2007 was satisfied using a combination of original issue shares and open market purchases of SCANA’s common stock. Cash and the related tax benefits realized from stock option exercises during the period were retained at SCANA.

4.      LONG-TERM DEBT

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

	Weighted-Average			Maturity		December 31,
Millions of dollars	Interest Rate			Date		2007			2006
First Mortgage Bonds (secured)		6.00	%		2009-2036	$	1,675		$	1,675
GENCO Notes (secured)		5.86	%		2011-2024		119			123
Industrial and Pollution Control Bonds		5.24	%		2012-2032		156			156
Other					2008-2027		73			80
Total debt							2,023			2,034
Current maturities of long-term debt							(13	)		(13	)
Unamortized discount							(7	)		(13	)
Total long-term debt, net						$	2,003		$	2,008

          The annual amounts of long-term debt maturities for the years 2008 through 2012 are summarized as follows:

Year	Millions of dollars
2008	$	13
2009		139
2010		17
2011		171
2012		17

On January 14, 2008 SCE&G issued $250 million of its First Mortgage Bonds having an annual interest rate of 6.05% and maturing on January 15, 2038.   The proceeds from the sale of these bonds will be used to repay short-term debt primarily incurred as a result of SCE&G’s construction program and for general corporate purposes.

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

5.      LINES OF CREDIT AND SHORT-TERM BORROWINGS

Details of lines of credit and short-term borrowings at December 31, 2007 and 2006, are as follows:

Millions of dollars	2007				2006
Lines of credit
SCE&G	$		400		$		400
Fuel Company			250				250
Committed total and available	$	650			$	650
Uncommitted (a):
Total	$	78			$	78
Used by SCANA		7				-
Available for use	$	71			$	78
Short-term borrowings outstanding
Commercial paper (270 or fewer days)	$	463.6			$	362.2
Weighted average interest rate		5.74		%		5.38		%

(a) Line of credit that either SCE&G, SCANA or a combination may use.

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

Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or bank loans.  SCE&G and Fuel Company have commercial paper programs in the amount of $350 million and $250 million, respectively.  All such borrowings are supported by five-year revolving credit facilities which expire on December 19, 2011.

Fuel Company commercial paper outstanding totaled $140.7 million and $123.7 million at December 31, 2007 and 2006, respectively, at weighted average interest rates of 5.72% and 5.38%, respectively.

SCE&G’s commercial paper outstanding totaled $322.9 million and $238.5 million at December 31, 2007 and 2006, respectively, at weighted average interest rates of 5.75% and 5.38%, respectively.

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, 2007, $55 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

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 2008 through 2012 is $2.4 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2007 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	583,176	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, 2007, 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 2007, 2006 and 2005 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, 2004		78,518			105,961			184,479		$	9.2
Shares Redeemed-$50 par value		(1,475	)		(6,600	)		(8,075	)		(0.4	)
Balance at December 31, 2005		77,043			99,361			176,404			8.8
Shares Redeemed-$50 par value		(2,608	)		(6,600	)		(9,208	)		(0.5	)
Balance at December 31, 2006		74,435			92,761			167,196			8.3
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

8.           INCOME TAXES

Total income tax expense (benefit) attributable to income (before cumulative effect of accounting change) for 2007, 2006 and 2005 is as follows:

Millions of dollars	2007			2006			2005
Current taxes:
Federal	$	62.9		$	69.6		$	(8.4	)
State		8.9			5.3			9.5
Total current taxes		71.8			74.9			1.1
Deferred taxes, net:
Federal		33.8			8.6			(7.5	)
State		3.6			5.2			(9.8	)
Total deferred taxes		37.4			13.8			(17.3	)
Investment tax credits:
Deferred-state		5.0			5.0			5.1
Amortization of amounts deferred-state		(2.6	)		(3.3	)		(1.9	)
Amortization of amounts deferred-federal		(2.7	)		(2.7	)		(2.7	)
Total investment tax credits		(0.3	)		(1.0	)		0.5
Synthetic fuel tax credits - federal		-			-			(134.2	)
Total income tax expense (benefit)	$	108.9		$	87.7		$	(149.9	)

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

Millions of dollars	2007			2006			2005
Net income	$	245.1		$	230.0		$	258.1
Income tax expense (benefit)		108.9			87.7			(149.9	)
Minority interest		7.4			7.0			5.5
Total pre-tax income		361.4			324.7			113.7
Income taxes on above at statutory federal income tax rate	$	126.5		$	113.6		$	39.8
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		9.7			7.9			1.9
Synthetic fuel tax credits		(17.4	)		(33.5	)		(181.9	)
Non-taxable recovery of Lake Murray back-up dam project carrying costs		(2.0	)		(2.3	)		(3.8	)
Amortization of federal investment tax credits		(2.7	)		(2.7	)		(2.7	)
Amended returns for prior years		-			-			(2.1	)
Domestic production activities deduction		(3.9	)		(1.0	)		(1.4	)
Other differences, net		(1.3	)		5.7			0.3
Total income tax expense (benefit)	$	108.9		$	87.7		$	(149.9	)

The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $815.3  million at December 31, 2007 and $788.2 million at December 31, 2006 are as follows:

Millions of dollars	2007		2006
Deferred tax assets:
Nondeductible reserves	$	91.9	$	90.6
Unamortized investment tax credits		51.4		58.2
Federal alternative minimum tax credit carryforward		-		22.1
Deferred compensation		14.5		25.0
Unbilled revenue		11.6		10.5
Other		14.4		9.0
Total deferred tax assets		183.8		215.4
Deferred tax liabilities:
Property, plant and equipment		830.0		828.9
Pension plan income		87.1		74.1
Deferred employee benefit plan costs		42.6		50.5
Deferred fuel costs		2.0		25.7
Other		37.4		24.4
Total deferred tax liabilities		999.1		1,003.6
Net deferred tax liability	$	815.3	$	788.2

 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 2003 are closed for additional assessment.  With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2003.  The IRS has closed the examination of S. C. Coaltech No. 1, LP, a synthetic fuel partnership in which SCE&G has an interest, for the 2004 tax year, resulting in that return being accepted as filed.   SCE&G continues to believe that all of its synthetic fuel tax credits have been properly claimed.

In connection with the initial adoption of FIN 48 effective January 1, 2007, the Company removed $15 million of previously recorded tax benefits from its balance sheet.  Because regulatory liabilities had been recorded for these previously recognized tax benefits under the provisions of SFAS 71, these benefits had never been recognized in the Company’s earnings or retained earnings.  As a result, the initial adoption of FIN 48 had no effect on the Company’s equity.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $15 million.  The Company anticipates that this unrecognized amount could change by the end of 2008, as it relates to litigation of a state issue which could be resolved by December 31, 2008.  Any change will be within the range of $0 to $15 million. Because any tax benefits recorded would be amortized into earnings over a number of years under SFAS 71, the impact on any individual year’s effective tax rate would be immaterial.   No material changes in the status of our tax positions have occurred subsequent to adoption. 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, 2007		$	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, 2007		$	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 or tax penalties in 2007, 2006 and 2005.

9.      FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2007 and 2006 were as follows:

	2007				2006
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	2,016.0	$	2,023.9	$	2,021.0	$	2,068.0
Preferred stock (subject to purchase or sinking funds)		7.9		7.0		8.3		7.8

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 New York Mercantile Exchange (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 recorded as a regulatory asset or liability.

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.

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.

10.    COMMITMENTS AND CONTINGENCIES

A.      Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $10 million per year.

The Company currently maintains policies (for itself and on behalf of Santee Cooper, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, the Company’s portion of the retrospective premium assessment would not exceed $14.1 million.

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

B.      Environmental

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 sets 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 have challenged the rule, seeking a change in the method CAIR uses to allocate sulfur dioxide emission allowances.  The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements.  Although compliance plans and costs to comply with the rule have not been determined, it is believed that such costs will be material and will be recoverable through rates.

The EPA issued a final rule referred to as the Clean Air Mercury Rule (CAMR) in 2005 establishing a mercury emissions cap and trade program for coal-fired power plants that required limits to be met in two phases, in 2010 and 2018. 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 cannot predict the effect of this ruling on implementation of CAMR state implementation plans (SIPS) and newly promulgated CAMR regulations by the states.

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

SCE&G has been named, along with 29 others, by the EPA as a PRP at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  In 2008, SCE&G, along with other parties, reached a settlement with the EPA and the U.S. Department of Justice on this matter.  The settlement, which is subject to court approval, would result in an allocation of cost, net of insurance recoveries, to SCE&G that is not material, and such cost is expected to be recoverable through rates.

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). The deferral includes the estimated costs associated with the following matters.

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 $11.9 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 through rates.  At December 31, 2007, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $16.7 million.

C.      Franchise Agreements

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

D.     Claims and Litigation

In May 2004, SCANA and SCE&G were served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA 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 overruled 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 plaintiff has appealed the ruling to the South Carolina Court of Appeals and the Court of Appeals has dismissed the appeal, determining that the Circuit court ruling is not immediately appealable.  Plaintiff’s motion for class certification was recently heard and correspondence from the Circuit Court indicates the judge’s intention to certify the class.  There has been no formal order and the class remains limited to easements in Charleston County.  SCANA 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.

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

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

E.           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 2009. Rent expense totaled approximately $15.8 million, $12.8 million and $11.7 million in 2007, 2006 and 2005, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2008	$	14
2009		9
2010		1
Thereafter		-
Total	$	24

At December 31, 2007, minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $3.4 million.

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 $728.3 million, $526.0 million and $439.4 million in 2007, 2006 and 2005, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2008	$	804
2009		200
2010		65
2011		15
2012		14
Thereafter		90
Total	$	1,188

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.           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, 2007, the Company has recorded an ARO of approximately $99 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $195 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	2007			2006
Beginning balance	$	279		$	309
Liabilities incurred		-			1
Liabilities settled		(1	)		(1	)
Accretion expense		16			16
Revisions in estimated cash flows		-			(46	)
Ending Balance	$	294		$	279

Revisions in estimated cash flows in 2006 related to the expectation of lower cost escalations associated with decommissioning Summer Station than had been assumed in the prior cash flow analysis.

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)

2007		Electric Operations		Gas Distribution	All Other		Adjustments/ Eliminations			Consolidated Total
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

2005
Customer Revenue	$	1,912	$	509		-		-		$	2,421
Intersegment Revenue		-		1		-	$	(1	)		-
Operating Income (Loss)		299		16		-		(3	)		312
Interest Expense		13		-		-		131			144
Depreciation and Amortization		450		15		-		-			465
Segment Assets		5,531		408	$	4		1,423			7,366
Expenditures for Assets		280		58		-		(8	)		330
Deferred Tax Assets		n/a		n/a		-		22			22

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 (benefit) 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, Expenditures for Assets and Deferred Tax Assets include the totals from the Company that are not allocated to the segments.

12.         QUARTERLY FINANCIAL DATA (UNAUDITED)

2007 Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	633	$	575	$	686	$	587	$	2,481
Operating income		81		109		188		120		498
Net income		38		54		99		54		245

2006 Millions of dollars
Total operating revenues	$	592	$	553	$	664	$	582	$	2,391
Operating income		103		113		159		93		468
Income before cumulative effect of accounting change		46		53		93		38		230
Cumulative effect of accounting change, net of taxes (1)		4		-		-		-		4
Net income		50		53		93		38		234

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

       Note 3.

PART II,

ITEMS 9,  9A AND 9A(T),

PART III

 AND

PART IV

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, 2007, 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 the Company'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, 2007. There has been no change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2007 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, 2007, 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, 2007. 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, 2007, 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.

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, 2007, 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, SCANA Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007, of SCANA Corporation and subsidiaries and our report dated February 29, 2008, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/DELOITTE & TOUCHE LLP

Columbia, South Carolina

February 29, 2008

ITEM 9A(T).  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2007, an evaluation was performed under the supervision and with the participation of SCE&G's management, including the CEO and 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, 2007. There has been no change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2007 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:

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, 2007, the effectiveness of such structure and procedures. This management report follows.

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.

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.

SCE&G's management assessed the effectiveness of SCE&G's internal control over financial reporting as of December 31, 2007. 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, 2007, 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.

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 22. 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 2008 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 26, 2007 to hold office until the next annual meeting of SCE&G's shareholders to be held on April 24, 2008.  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 68)

Director since 1983

Mr. Hipp has been a private investor since The Liberty Corporation’s acquisition in January 2006. Prior to its acquisition, Mr. Hipp served as Chairman, Chief Executive Officer and a director of the Liberty Corporation, a broadcasting holding company headquartered in Greenville, South Carolina. Mr. Hipp held these positions for more than five years.

Harold C. Stowe (Age 61)*

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 from his position as President of Canal Holdings, LLC, a forest products industry company, located in Conway, South Carolina. Mr. Stowe had served as President of Canal Holdings, LLC, and its predecessor company, since March 1997. Mr. Stowe is a director of Ruddick Corporation, in Charlotte, North Carolina.

G. Smedes York (Age 67)

Director since 2000

Mr. York is Chairman and Treasurer of York Properties, Inc., a full-service commercial and residential real estate company, in Raleigh, North Carolina. Mr. York has been associated with York Properties, Inc. since 1970. Mr. York is also Chairman of the Board of York Simpson Underwood, a residential real estate brokerage company, and of McDonald-York, Inc., a general contractor, both in Raleigh, North Carolina.

	Bill L. Amick (Age 64) 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 (poultry) 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 51) 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 46)* 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 61) 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 47) Director since 1997
Mr. Bennett has been Executive Vice President and Director of Public Affairs of First Citizens Bank, located in Columbia, South Carolina, since August 2002. Previously, he was President and Chief Executive Officer of South Carolina Community Bank, in Columbia, South Carolina, from May 2000 to July 2002.
Lynne M. Miller (Age 56) Director since 1997
Ms. Miller has been an environmental consultant since her retirement from Quanta Capital Holdings, Inc., a specialty insurer, in August 2006. From August 2005 to August 2006 she was a Senior Business Consultant at Quanta Capital Holdings. From April 2004 through July 2005, she was President of Quanta Technical Services LLC. She was Chief Executive Officer of Environmental Strategies Consulting LLC, a division of Quanta Technical Services LLC, from September 2003 through March 2004. Ms. Miller co- founded Environmental Strategies Corporation, an environmental consulting firm in Reston, Virginia, in 1986, and served as President from 1986 until 1995 and as Chief Executive Officer from 1995 until September 2003 when the firm was acquired by Quanta Capital Holdings, Inc. and its name was changed to Environmental Strategies Consulting LLC. Ms. Miller is a director of Adams National Bank, a subsidiary of Abigail Adams National Bancorp, Inc., in Washington, D.C.

Maceo K. Sloan (Age 58)*

Director since 1997

Mr. Sloan is Chairman, President and Chief Executive Officer of Sloan Financial Group, Inc., a financial holding company, and Chairman, Chief Executive Officer and Chief Investment Officer of both NCM Capital Management Group, Inc., and NCM Capital Advisers, Inc., investment management companies, in Durham, North Carolina. He has held these positions for more than five years. Mr. Sloan is a trustee of Teachers Insurance Annuity Association-College Retirement Equity Fund (TIAA-CREF) Funds Boards, Chairman of the Board of M&F Bancorp, Inc. and a director of its subsidiary, Mechanics and Farmers Bank, in Durham, North Carolina.

* 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.  Mr. Stowe has been determined by SCE&G's board of directors to be an audit committee financial expert within the meaning of Item 407(d)(5) of 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.

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	61	Chairman of the Board and Chief Executive Officer	*-present
J. E. Addison	47	Senior Vice President and Chief Financial Officer Vice President – Finance	2006-present *-2006
J. C. Bouknight	55	Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA	2004-present *-2004
S. D. Burch	50	Senior Vice President, Fuel Procurement and Asset Management	2003-present
S. A. Byrne	48	Senior Vice President-Generation, Nuclear and Fossil Hydro Senior Vice President-Nuclear Operations	2004-present *-2004
K. B. Marsh	52	President and Chief Operating Officer Senior Vice President and Chief Financial Officer	2006-present *-2006
F. P. Mood, Jr.	70	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, 2003

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 2007.

ITEM 11. EXECUTIVE COMPENSATION

SCANA: The information required by Item 11 is incorporated herein by reference to the captions “EXECUTIVE COMPENSATION,” “-Compensation Discussion and Analysis,” “-Compensation Committee Report,” “-Summary Compensation Table,” “-2007 Grants of Plan-Based Awards” “-Outstanding Equity Awards at 2007 Fiscal Year End,”  “-2007 Option Exercises and Stock Vested,” “-Pension Benefits,” “-2007 Nonqualified Deferred Compensation,” “-Potential Payments Upon Termination or Change in Control,” and “DIRECTOR COMPENSATION” in SCANA's definitive proxy statement for the 2008 annual meeting of shareholders.

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. The Chairman of the Committee reports the Committee’s recommendations on executive compensation to the Board of Directors. The Human Resources and Tax Departments support the Human Resources Committee in its duties, and the Committee may delegate authority to these departments to fulfill administrative duties relating to our compensation programs.

The Committee has the authority under its charter to retain, approve fees for, and terminate advisors, consultants and others as it deems appropriate to assist in the fulfillment of its responsibilities. The Committee has, however, historically chosen to use relevant information provided to us by management’s consultant, Hewitt Associates. The Committee uses this information to assist it in carrying out its responsibilities for overseeing matters relating to compensation plans and compensation of our senior executive officers. Using information provided by a national compensation consultant helps to assure the Committee that our policies for compensation and benefits are competitive and aligned with utility and general industry practices.

Compensation Committee Interlocks and Insider Participation

During 2007, decisions on various elements of executive compensation were made by the Human Resources Committee. No officer, employee or former officer or any related person of SCANA or 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 2007 were:

Mr. G. Smedes York, Chairman

Mr. James A. Bennett

Mr. William C. Burkhardt

Mrs. Sharon A. Decker

Mr. D. Maybank Hagood

Ms. Lynne M. Miller

Mr. Maceo K. Sloan

Compensation Discussion and Analysis

Objectives and Philosophy of Executive Compensation

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

·   Hiring and retaining premier executive talent;

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

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

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

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

The following discussion provides an overview of our compensation program for all of our senior executive officers (a group of 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 2007, senior executive compensation consisted primarily of three key components: base salary, short-term cash incentive compensation (under the Short-Term Annual Incentive Plan) and long-term equity-based incentive compensation (under the 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 perquisites. The Human Resources Committee makes its decisions about how to allocate senior executive officer compensation among base salary, short-term cash incentive compensation and long-term equity-based incentive compensation on the basis of information provided by our compensation consultant, and our goals of remaining competitive with the compensation practices of a group of surveyed companies and of linking compensation to our corporate performance and individual senior executive officer performance.

A more detailed discussion of each of these components of senior executive officer compensation, the reasons for awarding such types of compensation, the considerations in setting the amounts of each component of compensation, the amounts actually awarded for the periods indicated, and various other related matters 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 2007 were based on a compensation survey performed in 2005.  A new compensation study was performed by our compensation consultant in 2007 and that survey information was used to set 2008 compensation.  Prior to the consultant’s initiating the biennial market study, we assist our consultant in matching our positions with positions in its database by examining specific responsibilities of our positions.  If we are unable to find an exact match for one of our positions in the consultant’s database, we select the most similar position and we may request the market survey information be adjusted upward or downward to match our position as closely as possible.  We also may request an adjustment upward or downward to the survey data of a particular position if we believe the data does not appropriately match the level of a position in our organization.

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 not greater than four times SCANA's revenues. Market survey results for each position are adjusted using regression analysis to account for these differences in company revenues. To a large extent, the companies included in the survey results were those that had agreed to participate in market surveys included in our compensation consultant’s database.

The companies included in the market survey we used in connection with setting base salaries and short-term incentive compensation for 2007, and the states in which they are headquartered are listed below:

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

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

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

To make comparisons with the market survey results, 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 marketing, business and other corporate support functions). SCANA then attempts 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 11 years, and has been employed with us in various capacities, including Chief Financial Officer, for 29 years. Mr. Timmerman started his career as a certified public accountant. As our Chief Executive Officer, Mr. Timmerman has responsibility for strategic planning, development of our senior executive officers and oversight of all our operations.

Mr. Addison was appointed our Senior Vice President and Chief Financial Officer in April 2006, prior to which he had served as our Vice President - Finance since 2001. As Chief Financial Officer, he is responsible for all of our financial operations, including accounting, risk management, treasury, investor relations, shareholder services, taxation and financial planning, as well as our information technology functions. Mr. Addison is a certified public accountant, and has been with us for 16 years.

Mr. Marsh was appointed our President and Chief Operating Officer in April 2006, prior to which 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 23 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, core analysis, emergency planning, licensing and nuclear support services. He has been with us for 12 years, and has over 21 years experience in the nuclear industry.

Mr. Mood has been our Senior Vice President and General Counsel for three 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 2007, our Human Resources Committee reviewed summaries of compensation components (“tally sheets”) for all of our senior executive officers, including the Named Executive Officers. These tally sheets reflected changes in compensation from the prior year and affixed dollar amounts to each component of compensation. The Committee did not make any adjustments to executive compensation in 2007 based on its review of the tally sheets. The Committee 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, and insurance, retirement and other benefits, as a factor in determining the total compensation package for each senior executive officer.

Timing of Senior Executive Officer Compensation Decisions

Annual salary reviews 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 three-year cycle of long-term equity-based incentive compensation. Compensation determinations also may be made by the Committee at its other quarterly meetings in the case of newly hired executives or promotions of existing employees that could not be deferred until the February meeting. 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 2007.  The Human Resources Committee determined that the increases to base salary were necessary and appropriate in light of market survey data and the fact that, with the exception of two Named Executive Officers who received increases in base salary in connection with promotions, the Named Executive Officers did not receive increases in 2006.  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 helps to align the interests of senior executive officers with those of shareholders.

Short-Term Annual Incentive Plan

Our Short-Term Annual Incentive Plan provides financial incentives for performance in the form of opportunities for annual incentive cash payments. Participants in the Short-Term Annual Incentive Plan include not only our senior executive officers, but also approximately 190 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, and on each senior executive officer’s level of performance in achieving his or her individual financial and strategic objectives. In assessing accomplishment of objectives, the Committee considers the difficulty of achieving each objective, unforeseen obstacles or favorable circumstances that might have altered the level of difficulty in achieving the objective, overall importance of the objective to our long-term and short-term goals, and importance of achieving the objective to enhancing shareholder value. Changes in annual target short-term incentive levels can be made if there are changes in the senior executive officer’s salary grade level that warrant a target change.

The plan allows for an increase or decrease in short-term incentive award payout of up to 20% of the target award based on an individual’s performance in meeting individual financial and strategic objectives. The plan also allows for an increase or decrease in award payout of up to 50% of the target award based on the extent to which we achieve our pre-determined financial objectives. However, cumulative adjustments to target award payouts for all participants may not increase or decrease overall award levels by more than 50%. Individual awards may nonetheless be decreased or eliminated if the Human Resources Committee determines that actual results warrant a lower payout.

For Mr. Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis on the following financial and business objectives for 2007:

·   SCANA achieving earnings per share targets set to reflect published earnings per share growth 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 2007:

·   SCANA achieving earnings per share targets set to reflect published earnings per share growth guidance; and

·   Our achieving annual business objectives relating to our 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 2007 awards if performance objectives were met at threshold, target and maximum levels are set forth in the 2007 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 2007 are shown in the table below:

2007 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		20%	5%	12.5%	12.5%
Profitable Growth		10%	25%	25%
Customer Service		20%	15%		37.5%
Developing our People			5%	12.5%

SCANA did not achieve its earnings per share targets for 2007 and, 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 2007 Short-Term 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 2007 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:  continuing to implement workforce planning initiatives; effectively addressing new regulatory and legislative issues; focusing on safety and employee wellness; advancing an environmental strategy that meets requirements and anticipates future needs; ensuring the security of our people, assets and operations; maintaining focus on cost control and business efficiency; meeting future growth requirements; and focusing on excellence in customer service.

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 maintaining financial reporting compliance processes and procedures that meet the requirements of the Sarbanes-Oxley Act; analysis and documentation relating to regulatory decisions for 2007; monitoring financial markets and ensuring our financings are cost effective and appropriate for all enterprises and capital projects; redesigning internal financial planning; and increasing our visibility in the financial community.

Mr. Marsh’s award was based on his progress toward implementing our succession and leadership development plans; leadership-level participation in regulatory decisions and strategy; oversight of our implementation of North American Electric Reliability Council and Electric Reliability Organization reliability standards; evaluating and developing long-term growth strategies; and completion of project milestones on new meter reading technology.

Mr. Byrne’s award was based on his evaluation and decisions related to our 2009 peaking power needs; completion of equipment modifications at one of our generating stations; oversight and resolution of safety issues; and implementation of a communication plan on new generation options.

Mr. Mood’s award was based on his effective oversight of implementation of annual internal reporting and assessments relating to environmental issues; fostering collaborative relationships between our legal and regulatory  departments and our business units to include the provision of high quality legal and regulatory support; development and oversight of records management policies and procedures; and effective oversight of the legal, environmental, and corporate secretary departments’ staffing and management.

Discretionary Bonus Award

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

·   Two primary factors that held down financial performance significantly (mild weather and reduced synthetic fuel royalties) were not within the control of our employees;

·   Notwithstanding the two primary factors listed above, our management team excelled at implementing strategies, including cost control and non-core asset disposition, such that SCANA missed its earnings target by only one cent per share   ($2.74 versus $2.75); and

·   Our management team has continued to make substantial progress this year in addressing long-term strategic issues, such as planning for future expansion of generation capacity and pending environmental challenges.

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

Long-Term Equity Compensation Plan

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

A portion of each senior executive officer’s potential compensation consists of awards under 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, performance units and performance shares. In recent years, our only long-term equity-based awards have been in the form of performance shares and performance units. These long-term equity-based awards are granted subject to satisfaction of specific performance goals. For the 2007-2009 performance period, awards under the Long-Term Equity Compensation Plan consisted solely of performance shares. We have not awarded stock options since 2002 and have no plans to do so in the foreseeable future.

 We believe awards of performance units and performance shares align the interests of our executives with those of shareholders because the value of such awards is tied to our achieving financial and business goals that would be expected to affect the value of SCANA’s common stock.

Performance Share Awards

SCANA has been granting 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 performance shares into which awards are denominated at grant 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 to be applied to SCANA’s 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 date of the three-year performance period.

Components of 2005-2007 and 2006-2008 Performance Share Awards

For the 2005-2007 and 2006-2008 performance cycles, performance share awards to senior executive officers under the Long-Term Equity Compensation Plan were based on (1) SCANA’s TSR relative to the TSR of a group of peer companies over the three-year periods and (2) a three-year average growth in earnings component based on SCANA’s earnings per share under generally accepted accounting principles, with adjustments to be made to account for the cumulative effects of any mandated changes in accounting principles and the effects of any sales of certain investments or impairment charges related to certain investments (we refer to this component as growth in “EPS from ongoing operations”). TSR over the performance year 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.

Performance Criteria for the 2005-2007 Performance Share Awards Granted in 2005 and Award Payouts in 2008

Payouts for performance share awards granted in 2005 for the 2005-2007 performance period were based on SCANA achieving: (1) TSR in the top two-thirds 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 2%. Sixty percent of 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 EPS from ongoing operations was made to weight the external performance measure slightly higher than the internal performance measure.

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 were at less than the 33rd percentile and no payouts would exceed 150% of the target award.

For the three-year performance period 2005-2007, SCANA's TSR was below the 33rd percentile of the peer group’s TSR, which resulted in no payouts on the TSR component of the awards.

With respect to the EPS component of the 2005-2007 awards, executives would earn threshold payouts (equal to 50% of target award) at 2% average growth, target payouts (equal to 100% of target award) at 4% average growth and maximum payouts (equal to 150% of target award) at or above 6% average growth. Payouts were scaled between 50% and 150% based on the actual growth in EPS from ongoing operations achieved. No payouts would occur if average growth in EPS from ongoing operations over the period were less than 2% and no payouts would exceed 150% of target award. These threshold, target and maximum payout levels were consistent with the earnings growth guidance provided publicly by management at the time of the grants.

For the three-year performance period 2005-2007, SCANA’s average growth in EPS from ongoing operations was  2.3%, resulting in a payout of 57.5% of the EPS component of the awards. This payout, which occurred in February, 2008, is reflected in the 2007 Option Exercises and Stock Vested Table.

2007-2009 Performance Share Awards

In 2007, we made performance share awards to each of the Named Executive Officers.  Information about the components of the awards and the performance criteria for the 2007 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 2007 three-year period is provided in the 2007 Grants of Plan-Based Awards Table.

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 2005-2007 and 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.

Components of, and Performance Criteria for, the 2007-2009 Performance Share Awards and Earned Awards for the 2007 Performance Period

Performance share awards granted for the 2007-2009 period were based on (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.  For an explanation of GAAP-adjusted net earnings per share from operations, see the discussion of Results of Operations 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 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.

Performance measurement and award determination for the 2007-2009 period will be made on an annual basis (rather than the above described three-year measurement and determination used for prior 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 period and will be contingent upon the participant’s still being employed by us at the end of the period, subject to certain exceptions in the event of retirement, death or disability. 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 the 2005-2007 and 2006-2008 Plan performance cycles.

Sixty percent of the 2007-2009 target performance share awards are based on SCANA's TSR for each year of the three-year plan period compared with the peer group of utilities set forth below:

Allegheny Energy, Inc.; Alliant Energy Corporation; Ameren Corporation; American Electric Power; Aquila, Inc.; 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; Energy East Corporation; 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; 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.; Sierra Pacific Resources; Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UniSource Energy Corporation; Vectren Corporation; Westar Energy, Inc.; Wisconsin Energy Corporation; XCEL Energy, Inc.

The number of utilities included in the peer group used for TSR comparisons is larger than the number included in the market survey utility peer group we use for purposes of setting base salary and short- and long-term incentive 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 SCANA's performance against performance of other utilities in which they might have invested.

Payouts based on the TSR component of the 2007-2009 plan are scaled according to SCANA's ranking against the peer group. No payout is earned if SCANA performance is less than the 33rd percentile. 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 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 match the levels used by the companies in the market survey data.

For the first year of the 2007-2009 period, SCANA's TSR was at the 59th percentile, which resulted in awards on the TSR component being earned at 118% for the year, payment of which will be deferred until the end of the three-year period as discussed above.  See the Outstanding Equity Awards at 2007 Fiscal Year-End Table.

Forty percent of the 2007-2009 performance share awards are based on meeting SCANA's annual projections for growth in its GAAP-adjusted net earnings per share from operations. Executives would 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 would 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 year of the 2007-2009 period, SCANA’s GAAP-adjusted net earnings per share from operations were 5.8%, which resulted in awards on the earnings per share component being earned at 145% for the year, payment of which will be deferred until the end of the three-year period as discussed above.

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

As discussed below under the caption “Compensation for 2008,” we have made further modifications to the design of awards under the Long-Term Executive Compensation Plan for 2008 awards.

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 non-tax qualified defined benefit Supplemental Executive Retirement Plan (the “SERP”) for our senior executive officers;

·   a tax qualified defined contribution plan (the “401(k) Plan”); and

·   a non-tax qualified defined contribution Executive Deferred Compensation Plan (the “EDCP”) for our senior executive officers.

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

The SERP and the EDCP plans are designed to provide a benefit to senior executive officers who participate in the Retirement Plan or 401(k) Plan (our tax-qualified retirement plans) and whose participation in those tax-qualified plans 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 and the EDCP are described under the caption “Potential Payments Upon Termination or Change in Control — Retirement Benefits.”   We provide the SERP and EDCP benefits because they allow our senior executive officers the opportunity to defer the same percentage of their compensation as other employees. We also believe, based on market survey data, that these plans are necessary to make our senior executive officer retirement benefits competitive.

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

Termination, Severance and Change in Control Arrangements

We have entered into arrangements with certain of our senior executive officers, including our Named Executive Officers, that provide for payments to them in the event of a change in control of 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.” 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 very rare occasions, a senior executive officer may use our aircraft for personal use that is not in connection with a business purpose. We impute income to the executive for certain expenses related to such use.

For purposes of determining total 2007 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 free installation and provide monitoring of home security systems for our senior executive officers. Because we operate a nuclear facility and provide essential services to the public, we believe we have a duty to help assure uninterrupted and safe operations by protecting the safety and security of our senior executive officers. We provide such installation and monitoring at multiple homes for some senior executive officers.

Other Perquisites

We provide a taxable allowance to our senior executive officers for financial counseling services, including tax preparation and estate planning services. We value this benefit based on the actual charges incurred. We also pay the initiation fees and monthly dues for one dining club membership for each senior executive officer for business use. We allow spouses to accompany directors and senior executive officers to our quarterly Board meetings because we believe social gatherings of directors and senior executive officers in connection with these meetings increases collegiality. Some of our meetings are at resort locations where resort amenities may be provided.

Accounting and Tax Treatments of Compensation

Deductibility of Executive Compensation

Section 162(m) of the Internal Revenue Code establishes a limit on the deductibility of annual compensation in excess of $1,000,000 for certain senior executive officers, including the Named Executive Officers. Certain performance-based compensation approved by shareholders is not subject to the deduction limit. Our Long-Term Equity Compensation Plan is qualified so that most performance- based awards under that plan constitute compensation that is not subject to Section 162(m). Our Short-Term Incentive Plan does not meet 162(m) deductibility requirements. To maintain flexibility in compensating senior executive officers in a manner designed to promote various corporate goals, the Human Resources Committee has not adopted a policy that all compensation must be deductible. Since Mr. Timmerman’s salary 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 are 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. In the meantime, the plans must operate in good faith compliance with Section 409A, and we believe our deferred compensation plans meet this requirement. We have determined that amendments will be required to the Supplemental Executive Retirement Plan, the Executive Deferred Compensation Plan, the Director Compensation and Deferral Plan, the Key Executive Severance Benefits Plan and the Supplementary Key Executive Severance Benefits Plan to cause these plans to comply with Section 409A. The Human Resources Committee expects to continue to address these amendments in 2008.

Accounting for Stock Based Compensation

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

Compensation for 2008

On February 14, 2008, the Board, on the recommendation of the Human Resources Committee, adopted criteria for performance awards for the 2008 - 2010 period under the Long-Term Equity Compensation Plan.  These criteria are different from those adopted for prior performance awards for the reasons discussed below.

As discussed above under “Long-Term Equity Compensation Plan,” each of the grants for the three-year performance cycles, 2005-2007 and 2006-2008, under the Long-Term Equity Compensation Plan provided for awards of performance shares, 60% of which would be earned based on our level of success in achieving certain SCANA TSR targets as compared to the TSR of a peer group of companies over the three-year cycles, and 40% of which would be earned based on our level of success in achieving certain SCANA EPS growth targets over the three year cycles.  The performance share awards for the 2007-2009 period also provided for the 60/40% allocation between TSR and EPS growth components, but with annual, instead of three-year, measurement periods.

The performance thresholds were not met with respect to either the SCANA TSR or EPS growth components for the 2004-2006 cycle which resulted in no performance shares being earned and no payouts, and the performance threshold was not met with respect to the SCANA TSR component for the 2005-2007 cycle, which resulted in no performance shares being earned and no payout on the TSR component for this 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 only 23%. The performance threshold is also not projected to be met with respect to the SCANA TSR component for the 2006-2008 cycle, and is only projected to be met between threshold and target with respect to the SCANA EPS component for this cycle.

We believe the principal reason for the below threshold performance with respect to the TSR component of the awards is 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 our shareholders and the communities we serve, but it appears to us that the financial markets may have a shorter term focus. Although alignment of our executives’ interests with shareholder interests is very important, we, along with our employees, have consistently focused on our executives’ long-term performance.  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 have made further adjustments to the design of our awards under the Long Term Equity Compensation Plan.

Because we believe our plans to build new generation capacity are a primary reason for our failure to meet SCANA TSR targets, we asked our compensation consultant to compile a group of twenty-five peer companies and include a group of twelve other utilities that have announced an interest in expanding generation capacity, including consideration of building new nuclear facilities.  The survey revealed that 96% of these utilities use performance plans, but 80% of them also grant restricted stock or stock options.  Only four of the companies (16%) use only performance plans.  The survey also indicated that most of these other companies have wider performance and payout ranges than we do. SCANA's TSR performance range is 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.  Additionally, the survey indicated that some of the modified peer group companies have lower minimum payouts and higher maximum payouts than we do.  Whereas we pay out 50% of target award at threshold performance (33%), median 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.

Taking into consideration the disparities between our plan awards and those of this modified peer group, the Committee approved the following changes to the 2008-2010 awards under the Long Term Equity Compensation Plan as compared to the awards for the two prior cycles:

·   Instead of awards being denominated in all performance shares which are based 60% on our level of achieving SCANA’s TSR targets and 40% on our level of achieving SCANA’s EPS growth targets, awards for the 2008-2010 period will be comprised of a combination of performance shares and restricted stock.  Performance shares will represent 80% of the awards, consisting of one half to be earned based on our level of achieving SCANA's TSR targets and the remaining one half to be earned based on our level of achieving SCANA's EPS growth targets.  The remaining 20% of the awards will be in restricted stock.  The restricted stock will vest in 36 months 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.

·   Instead of the SCANA TSR threshold for payout on performance share awards being set at the 33rd percentile of the peer group performance and paying out 50% of target, the SCANA TSR threshold for payout will be reduced to the 25th percentile of peer group TSR performance and payout will start at 25% of target.

·   Instead of the SCANA TSR maximum payout on performance share awards being set at the 150th percentile if we achieve 75% or more of peer group TSR performance, maximum SCANA TSR payout will be increased to the 175th percentile of target if we achieve 90% of peer group performance.

·   Instead of the SCANA EPS growth threshold for payout on performance share awards being set at 2% and paying out at 50% of target, the SCANA EPS growth threshold for payout will be reduced to 1% and payout will start at 25%.

·   Instead of the SCANA EPS growth maximum for payout on performance share awards being set at 6% and paying out at 150% of target, the SCANA EPS growth maximum for payout will be increased to 7% with a maximum payout of 175%.

The performance results for the 2008-2010 period will continue to be measured on an annual basis.

We believe these changes are consistent with our goals of retaining our executives and encouraging them to focus on our long-term performance goals.

On the same day, upon recommendation of the Human Resources Committee, the Board approved base salaries for our Named Executive Officers and criteria for performance awards under our Short-Term Annual Incentive Plan for the year 2008. Such base salaries and performance award criteria do not differ materially from year 2007 levels.

As noted above, in 2008, the Human Resources Committee expects to make amendments to our deferred compensation plans as necessary to address issues raised by Internal Revenue Code Section 409A.

Financial Restatement

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

Security Ownership Guidelines for Executive Officers

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

Compensation Committee Report

The Human Resources Committee has reviewed and discussed with management the “Compensation Discussion and Analysis” included 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, 2007 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

Ms. Lynne M. Miller

Mr. Maceo K. Sloan

SUMMARY COMPENSATION TABLE

The following table summarizes information about compensation paid or accrued during 2007 and 2006 to our Chief Executive Officer, our Chief Financial Officer and our three next most highly compensated executive officers during 2007. (As noted in the Compensation Discussion and Analysis, we refer to these persons as our Named Executive Officers.)

Name and Principal Position		Year	Salary ($)	Bonus ($)(1)	Stock Awards ($)(2)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
W. B. Timmerman, 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		2007 2006	$303,846 $278,990	$36,600 $27,916	$252,274 $37,505	- -	$91,500 $69,789	$41,300 $21,981	$29,242 $30,091	$754,762 $466,272
K. B. Marsh, President and Chief Operating Officer		2007 2006	$548,115 $516,183	$71,500 $66,916	$613,229 $106,749	- -	$178,750 $167,290	$113,085 $59,934	$53,730 $63,816	$1,578,409 $980,888
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		2007 2006	$368,462 $350,000	$37,000 $35,000	$285,537 $50,033	- -	$92,500 $87,500	$49,607 $59,582	$37,465 $41,051	$870,571 $623,166

(1) Discretionary bonus awards as permitted under the 2007 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 2007 information in this column relates to 2007-2009 performance share awards (liability awards) under the Long-Term Equity Compensation Plan. This plan is discussed under “—Compensation Discussion and Analysis — Long-Term Equity Compensation Plan.” The figures for 2007 also 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 FAS 123(R). The assumptions made in valuation of stock awards are set forth in Note 3 to the audited financial statements for the year ended December 31, 2007, which are included in ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA in Part II above.

The 2006 information in this column reflects the amounts we recorded as compensation expense and amounts which were capitalized in our financial statements. 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 2007 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, 2006 to December 31, 2007, 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.”

(5) All other compensation paid to each Named Executive Officer, including company contributions to the 401(k) Plan and the Executive Deferred Compensation Plan, tax reimbursements with respect to perquisites or other personal benefits, and life insurance premiums on policies owned by Named Executive Officers.  For 2007, the Company contributions to defined contribution plans were as follows: Mr. Timmerman — $100,511; Mr. Addison — $24,560; Mr. Marsh — $48,039; Mr. Byrne — $36,033; and Mr. Mood — $30,233. For 2007, tax reimbursements with respect to perquisites or other personal benefits were as follows: Mr. Timmerman — $0; Mr. Addison — $0; Mr. Marsh — $0; Mr. Byrne — $804; and Mr. Mood — $210.  Neither life insurance premiums on policies owned by the Named Executive Officers nor perquisites exceeded $10,000 for any Named Executive Officer with the exception of Mr. Timmerman.  Mr Timmerman’s All Other Compensation includes perquisites of $14,449 consisting of expenses related to the Company provided medical examination and transportation to and from the medical examination on the Company plane, financial planning services, and travel expenses associated with his spouse’s occasionally accompanying him on business travel.

2007 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 2007.

		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payouts Under Equity Incentive Plan Awards(2)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)	All Other Stock Awards: Number of Shares of Stock or Units (#)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/Sh)	Grant Date Fair Value of Stock and Option Awards
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)
W. B. Timmerman	2-15-07 2-15-07	$444,890	$889,780	$1,334,670	33,773	67,546	101,319
J. E. Addison	2-15-07 2-15-07	$91,500	$183,000	$274,500	5,412	10,824	16,236
K. B. Marsh	2-15-07 2-15-07	$178,750	$357,500	$536,250	11,978	23,956	35,934
S. A. Byrne	2-15-07 2-15-07	$126,000	$252,000	$378,000	7,453	14,906	22,359
F. P. Mood, Jr.	2-15-07 2-15-07	$92,500	$185,000	$277,500	5,671	11,341	17,012

(1) The amounts in columns (c), (d) and (e) represent the threshold, target and maximum awards that could have been paid under the 2007 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 its earnings per share objectives, but all of the Named Executive Officers met and exceeded 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 2007 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.

(2) Represents total potential future payouts of the 2007-2009 performance share awards under the Long-Term Equity Compensation Plan. Payout of performance share awards at the end of the 2007-2009 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 2007 performance period have been earned at 118% of target for the SCANA TSR portion and 145% of target for the SCANA EPS portion, but have not vested.  A discussion of the components of the performance share awards is included under “—Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — 2007-2009 Performance Share Awards.”

OUTSTANDING EQUITY AWARDS AT 2007 FISCAL YEAR-END

The following table sets forth certain information regarding unexercised options and equity incentive plan awards for each Named Executive Officer outstanding as of December 31, 2007.

	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)(1)	Market Value of Shares or Units of Stock That Have Not Vested ($)(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)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
W. B. Timmerman						29,000	$1,222,350	116,608	$4,915,027
J. E. Addison						4,647	$195,871	16,922	$713,262
K. B. Marsh						10,285	$433,513	41,312	$1,741,301
S. A. Byrne						6,400	$269,760	25,681	$1,082,454
F. P. Mood, Jr.						4,869	$205,228	19,476	$820,913

(1) These awards, which were earned for 2007 under the 2007-2009 Long-Term Equity Compensation Plan period based on achieving SCANA’s TSR at the 59th percentile and growth in SCANA's GAAP adjusted net earnings per share of 5.8%, 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, 2007 of $42.15.

(3) 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, 49,062 shares would vest on December 31, 2008 and 96,546  shares would vest on December 31, 2009; Mr. Addison, 6,098 shares would vest on December 31, 2008 and 15,471 shares would vest on December 31, 2009; Mr. Marsh, 17,356 shares would vest on December 31, 2008 and 34,241 shares would vest on December 31, 2009; Mr. Byrne, 10,775 shares would vest on December 31, 2008 and 21,306 shares would vest on December 31, 2009; and Mr. Mood, 8,135 shares would vest on December 31, 2008 and 16,210 shares would vest on December 31, 2009.

(4) For the 2006-2008 cycle, performance shares tracking against SCANA’s TSR (60% of target shares) are projected to result in no payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the threshold performance measure for the 2006-2008 TSR portion of the shares. Performance shares tracking against SCANA’s growth in EPS from ongoing operations (40% of target shares) for the 2006-2008 performance cycle are projected to result in a payout between threshold and target. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the target performance measure for the 2006-2008 growth in EPS from ongoing operations portion of the shares. For each of the 2008 and 2009 periods remaining in the 2007-2009 awards, performance shares tracking against SCANA’s TSR (60% 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 2008 and 2009 TSR portions of the shares. Performance shares tracking against SCANA’s growth in GAAP adjusted net earnings per share (40% of target shares) for the 2008 and 2009 periods remaining in the 2007-2009 awards are also 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 the growth in these 2008 and 2009 GAAP adjusted net earnings per share portions of the shares.

2007 OPTION EXERCISES AND STOCK VESTED

The following table sets forth information about exercises of SCANA stock options for each Named Executive Officer during 2007.

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)(1)	Number of Shares Acquired on Vesting (#)(2)	Value Realized on Vesting ($)(2)
(a)	(b)	(c)	(d)	(e)
W. B. Timmerman	123,067	$1,802,932	16,458	$693,705
J. E. Addison			1,333	$56,186
K. B. Marsh			5,130	$216,230
S. A. Byrne	21,492	$353,328	2,793	$117,725
F. P. Mood, Jr.			2,155	$90,833

(1)   The difference between the exercise prices paid and the closing prices of SCANA common stock on the date of exercise.

(2)   Represents portion of 2005-2007 Performance Share Awards that vested based on our achieving the earnings per share component at slightly above threshold. These awards were paid in cash.

PENSION BENEFITS

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

Name (a)	Plan Name (b)	Number of Years Credited Service (#)(1) (c)	Present Value of Accumulated Benefit ($)(1)(2) (d)	Payments During Last Fiscal Year($) (e)
W. B. Timmerman	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	29 29	$858,115 $2,355,544	$0 $0
J. E. Addison	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	16 16	$151,048 $87,255	$0 $0
K. B. Marsh	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	23 23	$465,241 $441,485	$0 $0
S. A. Byrne	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	12 12	$132,060 $215,304	$0 $0
F. P. Mood, Jr.	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	3 3	$55,326 $84,476	$0 $0

(1) Computed as of December 31, 2007, 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 2007, 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, 2007, 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. 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 Retirement Plan is a tax qualified defined benefit retirement plan. SCE&G participates in this 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 our Retirement Plan for all employees, SCANA provides a Supplemental Executive Retirement Plan for certain eligible employees, including the Named Executive Officers. The Supplemental Executive Retirement Plan is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations. The Supplemental Executive Retirement Plan is discussed under the caption “— Potential Payments Upon Termination or Change in Control — Retirement Benefits,”, and under the caption “— Compensation Discussion and Analysis — Retirement and Other Benefit Plans.”

2007 NONQUALIFIED DEFERRED COMPENSATION

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

Name (a)	Executive Contributions in Last FY ($)(1) (b)	Registrant Contributions in Last FY ($)(1) (c)	Aggregate Earnings in Last FY ($) (d)	Aggregate Withdrawals/ Distributions ($) (e)	Aggregate Balance at Last FYE ($) (f)
W. B. Timmerman	$84,799	$87,011	$188,931	$0	$3,013,350
J. E. Addison	$12,207	$11,199	$18,352	$0	$366,860
K. B. Marsh	$33,383	$34,539	$40,858	$0	$1,214,118
S. A. Byrne	$21,654	$22,533	$34,057	$0	$517,412
F. P. Mood, Jr.	$25,981	$16,939	($1,715)	$0	$109,737

(1) The amounts reported in columns (b) and (c) are reflected in columns (c) and (i), respectively, of the Summary Compensation Table.

Executive Deferred Compensation Plan

We have adopted the SCANA Corporation Executive Deferred Compensation Plan, in which our Named Executive Officers may participate if they choose to do so. The plan is a non-qualified deferred compensation plan. Each participant may elect to defer up to 25% of that part of his or her eligible earnings (as defined in the 401(k) plan) that exceeds the limitation on compensation otherwise required under Internal Revenue Code Section 401(a)(17), without regard to any deferrals or the foregoing of compensation. For 2007, participants could defer eligible earnings in excess of $225,000. In addition, a participant may elect to defer up to 100% of any performance share award for the year under our Long-Term Equity Compensation Plan. We match the amount of compensation deferred by each participant up to 6% of the participant’s eligible earnings in excess of the limit amount not including any performance share award.

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

In 2007, the Named Executive Officers’ special ledger accounts were credited with earnings (or losses) based on the following investment alternatives and rates of returns:

INVESCO Stable Value Trust (4.14%); PIMCO Total Return (8.81%); Dodge & Cox Common Stock ( 0.14%); American Century Inc. & Growth Adv. (-0.54%); INVESCO 500 Index Trust (5.18%); Pioneer Oak Ridge Large Cap Growth (7.61%); T. Rowe Price Mid Cap Value (0.60%); Times Square Mid Cap Growth Fund  (10.11%); RS Partners (-3.78%); Vanguard Explorer (5.26%); American Funds Europacific Growth (18.96%); SCANA Corporation Stock (8.36%); Vanguard Target Retirement Income (8.17%); Vanguard Target Retirement 2005 (8.12%); Vanguard Target Retirement 2015 (7.55%); Vanguard Target Retirement 2025 (7.59%); Vanguard Target Retirement 2035 (7.49%); Vanguard Target Retirement 2045 (7.47%).

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.

All amounts deferred under the Executive Deferred Compensation Plan, other than matching deferrals and earnings thereon may be paid at a date certain prior to termination of employment or at termination of employment, death, disability or retirement.  Matching deferrals credited to a participant’s special ledger account as well as all other deferrals and earnings thereon are required to be paid, or to begin to be paid, as soon as practicable following the participant’s death, disability, retirement or other termination of employment.  Payments made before termination of employment may only be made in the form of a single sum cash distribution.  Payments made after termination of employment but before retirement may only be made in the form of a single sum cash distribution.  Payments made after retirement, death or disability are to be paid in the form of a single sum cash distribution, or, at the participant’s election, may be paid in annual installments over a period not to exceed fifteen years.

A participant may request and receive, with the approval of the committee, an acceleration of the payment of some or all of the participant’s special ledger account due to severe financial hardship as the result of extraordinary and unforeseeable circumstances arising as a result of events beyond the individual’s control. With respect to amounts earned and vested before January 1, 2005, and earnings thereon, a participant may also obtain payment of this special ledger account on an accelerated basis by forfeiting 10% of the amount accelerated or by making the election 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.”

For amounts earned and vested after January 1, 2005, distribution and withdrawal elections are subject to Internal Revenue Code Section 409A. During 2008, we plan to amend all available distribution and withdrawal options with respect to amounts earned or vested after 2004 to conform to the new requirements for deferred compensation under Section 409A.  Although the Internal Revenue Service does not require that changes to conform to Section 409A be made before December 31, 2008, we were required to operate in good faith compliance with Section 409A from January 1, 2005 forward, subject to guidance issued by the Internal Revenue Service.

Potential Payments Upon Termination or Change in Control

Change in Control Arrangements

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

We have adopted the SCANA Corporation Key Executive Severance Benefits Plan and the SCANA Corporation Supplementary Key Executive Severance Benefits Plan, which provide for payments to our senior executive officers in connection with a change in control of our Company. The Key Executive Severance Benefits Plan (the “Severance Plan”) provides for payment of benefits in a lump sum immediately upon a change in control unless the plan has been terminated prior to the change in control. This plan is designed to provide for benefits in the event of a change in control that our Board deems to be hostile. In the event of a change in control that our Board deems to be friendly, we anticipate that the Board would terminate the Severance Plan prior to the change in control. If the Severance Plan is terminated, the Supplementary Key Executive Severance Benefits Plan (the “Supplementary Severance Plan”) would provide for payment of benefits if, within 24 months after the change in control, we terminate a senior executive officer’s employment without just cause or if the senior executive officer terminates his or her employment for good reason.

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. Although no compensation decisions were made in 2007 as a result of the Committee’s review of the benefits payable under these plans, the Committee intends to make amendments to the plans in 2008 to comply with the current December 31, 2008 409A compliance deadline.

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 (a) were directors on the Board at the beginning of such period, or (b) became directors after the beginning of such period but whose election by the Board, or nomination for election by our shareholders, was approved by at least two-thirds of the directors then still in office who either were directors at the beginning of such period, or whose election or nomination for election was previously so approved;

·   if SCANA shareholders approve (a) 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), (b) a plan of complete liquidation of SCANA, or (c) 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, 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:

·   he or she were assigned to duties inconsistent with his or her duties, or had a reduction or alteration in the nature or status of his or her responsibilities, from those in effect 90 days prior to the change in control;

·   we reduced his or her base salary as in effect 30 days prior to the occurrence of certain preliminary actions preceding the change in control (such as the execution of agreements relating to a change in control, public announcements by us of our intentions, transfers of securities representing at least 8 1¤2% of SCANA’s stock or the adoption of board resolutions with respect thereto);

·   after the change in control, we required him or her to be based more than 25 miles from his or her location as of the effective date of the Supplementary Severance Plan;

·   we failed to continue to offer any annual or long-term incentive programs for officers which were in effect on the effective date of the change in control, or other employee benefit plans, policies, practices or arrangements in which he or she participates, unless similar plans of equal value are put in place, or we failed to permit him or her to continue participation on substantially the same basis as existed on the date of the change in control;

·   we failed to obtain a satisfactory agreement from any successor to assume and perform the Supplementary Severance Plan; or

·   we purported to terminate him or her without using a notice of termination that satisfies the requirements of the Supplementary Severance Plan.

Potential Benefits Payable

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

·   An amount intended to approximate three times the sum of: (i) his or her annual base salary (before reduction for certain pre-tax deferrals) and (ii) his or her full targeted annual incentive award, in each case as in effect for the year in which the change in control occurs;

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

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

In addition to the benefits above, immediately upon a change in control prior to which we had not terminated the Severance Plan (unless their agreements with us provide otherwise), our senior executive officers would also be entitled to benefits under our other plans in which they participate as follows:

·   A benefit distribution of all amounts credited to his or her Executive Deferred Compensation Plan ledger account as of the date of the change in control;

·   A benefit distribution under the Long-Term Equity Compensation Plan equal to 100% of the target performance share award for all performance periods not completed as of the date of the change in control, if any;

·   A benefit distribution under the Short-Term Annual Incentive Plan equal to 100% of the target award in effect as of the date of the change in control;

·   Under the Long-Term Equity Compensation Plan and related agreements, all nonqualified stock options awarded and non-vested target performance shares would become immediately exercisable or vested and remain exercisable throughout their original term or, in the case of performance shares, vested and payable within 30 days of the change in control; and

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

Under the Supplementary Severance Plan, senior executive officers would also be entitled to all of the benefits described above. In addition, interest would be paid on the benefits payable under the Executive Deferred Compensation Plan at a rate equal to the sum of the prime interest rate as published in the Wall Street Journal on the most recent publication date prior to the date of the change in control plus 3%, calculated through the end of the month preceding the month in which the benefits are distributed. Any amounts payable under the Supplementary Severance Plan would be reduced by all amounts, if any, received under the Severance Plan.

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

Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 31, 2007

Severance Plan

If we had been subject to a change in control as of December 31, 2007, 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 2007 base salary and target short-term incentive award — $5,809,740; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $674,972; an amount equal to insurance continuation benefits for three years — $37,239; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $5,801,273; and anticipated excise tax and gross-up payment — $5,499,025. The total value of these change in control benefits would have been $17,822,249. In addition, Mr. Timmerman would have been paid amounts previously earned, but not yet paid, as follows: 2007 target short-term annual incentive award — $889,780; 2007 actual long-term equity award —  $774,760; Executive Deferred Compensation Plan account balance — $3,013,350; Supplemental Executive Retirement Plan and Retirement Plan account balances — $3,366,124; vacation accrual — $40,261; 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 2007 base salary and target short-term incentive award — $1,464,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $553,456; an amount equal to insurance continuation benefits for three years — $69,375; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $823,400; and anticipated excise tax and gross-up payment — $1,365,729. The total value of these change in control benefits would have been $4,275,960. In addition, Mr. Addison would have been paid amounts previously earned, but not yet paid, as follows: 2007 target short-term annual incentive award — $183,000; 2007 actual long-term equity award — $62,751; Executive Deferred Compensation Plan account balance — $366,860; Supplemental Executive Retirement Plan and Retirement Plan account balances — $294,298; vacation accrual — $10,264; 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 2007 base salary and target short-term incentive award — $2,722,500; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $850,458; an amount equal to insurance continuation benefits for three years — $52,371; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $2,054,813; and anticipated excise tax and gross-up payment — $2,468,698. The total value of these change in control benefits would have been $8,148,840. In addition, Mr. Marsh would have been paid amounts previously earned, but not yet paid, as follows: 2007 target short-term annual incentive award — $357,500; 2007 actual long-term equity award — $241,495; Executive Deferred Compensation Plan account balance — $1,214,118; Supplemental Executive Retirement Plan and Retirement Plan account balances — $1,054,403; vacation accrual — $9,916; 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 2007 base salary and target short-term incentive award — $2,016,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $760,940; an amount equal to insurance continuation benefits for three years — $71,740; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $1,277,103; and anticipated excise tax and gross-up payment — $1,855,127. The total value of these change in control benefits would have been $5,980,910. In addition, Mr. Byrne would have been paid amounts previously earned, but not yet paid, as follows: 2007 target short-term annual incentive award — $252,000; 2007 actual long-term equity award — $131,480; Executive Deferred Compensation Plan account balance — $517,412; Supplemental Executive Retirement Plan and Retirement Plan account balances — $424,775; vacation accrual — $10,904; 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 2007 base salary and target short-term incentive award — $1,665,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $0; an amount equal to insurance continuation benefits for three years — $54,395; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $967,848; and anticipated excise tax and gross-up payment — $1,219,918. The total value of these change in control benefits would have been $3,907,161. In addition, Mr. Mood would have been paid amounts previously earned, but not yet paid, as follows: 2007 target short-term annual incentive award — $185,000; 2007 actual long-term equity award — $101,447; Executive Deferred Compensation Plan account balance — $109,737; Supplemental Executive Retirement Plan and Retirement Plan account balances — $139,802; vacation accrual — $11,384; as well as his 401(k) Plan account balance.

In addition to the foregoing benefits, all option and stock awards set forth in the 2007 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, 2007, either we had terminated the employment of any of our Named Executive Officers without just cause or they had terminated their employment for good reason, such terminated Named Executive Officer would have been immediately entitled to all of the benefits outlined above, together with an amount equal to an increase in the amount payable with respect to his Executive Deferred Compensation Plan account, calculated as outlined above. The actual amount of any such additional payment would depend upon the date on which employment of the Named Executive Officer terminated subsequent to the change in control.

Retirement Benefits

Supplemental Executive Retirement Plan

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

Subject to the terms of the SERP, a participant becomes eligible to receive benefits under the SERP upon termination of his or her employment with us (or at such later date as may be provided in a participant’s agreement with us), if the participant has become vested in his or her accrued benefit under the Retirement Plan prior to termination of employment. However, if a participant is involuntarily terminated following or incident to a change in control and prior to becoming fully vested in his or her accrued benefit under the Retirement Plan, the participant will automatically become fully vested in his benefit under the SERP and a benefit will be payable under the SERP. The term “change in control” has the same meaning in the SERP as in the Severance Plan and the Supplementary Severance Plan. See the discussion under “Change in Control Arrangements.”

Unless otherwise provided in a participant agreement, the amount of any benefit payable to a participant under the SERP will be determined as of the date he or she first becomes eligible to receive benefits under the SERP, and will be equal to (i) the cash balance account that otherwise would have been payable under the Retirement Plan as of such determination date, based on compensation and disregarding the limitations imposed by the Internal Revenue Code on the amount of annual retirement benefits payable to employees from qualified pension plans and on the amount of annual compensation that may be taken into account for all qualified plan purposes, minus (ii) the participant’s cash balance account determined under the Retirement Plan as of such determination date. For purposes of the SERP, “compensation” is defined as determined under the Retirement Plan, without regard to the limitation under Section 401(a)(17) of the Internal Revenue Code, including any amounts of compensation otherwise deferred under any non-qualified deferred compensation plan (excluding the SERP).

The benefit payable to a participant under the SERP will be paid, or commence to be paid, as of the first day of the calendar month following the date the participant first becomes eligible to receive a benefit under the SERP. With respect to amounts earned and vested before January 1, 2005, the participant may elect, in accordance with procedures we establish, to receive a distribution of such benefit in either of the following two forms of payment:

·   A single sum distribution of the value of the participant’s benefit under the SERP determined as of the last day of the month preceding the date he or she first becomes eligible to receive benefits; or

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

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

Unless otherwise provided in a participant agreement, if a participant dies before the first day of the calendar month after he or she becomes eligible to receive benefits under the SERP, a single sum distribution equal to the value of the benefit that otherwise would have been payable under the SERP will be paid to the participant’s designated beneficiary as soon as administratively practicable following the participant’s death. With respect to SERP amounts earned and vested on or after January 1, 2005, the available distribution options will be limited in accordance with Section 409A of the Internal Revenue Code.

Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 31, 2007

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, 2007 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, 2007.

For Mr. Timmerman, the lump sum amount would have been $2,467,298, or the monthly payments would have been $15,411 for the remainder of his lifetime. In the event he had died December 31, 2007 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $9,246 for up to 15 years. If Mr. Timmerman had died December 31, 2007 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Addison, the lump sum amount would have been $107,758, or the monthly payments would have been $530 for the remainder of his lifetime. In the event he had died December 31, 2007 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $318 for up to 15 years. If Mr. Addison had died December 31, 2007 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Marsh, the lump sum amount would have been $513,389, or the monthly payments would have been $2,709 for the remainder of his lifetime. In the event he had died December 31, 2007 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $1,626 for up to 15 years. If Mr. Marsh had died December 31, 2007 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Byrne, the lump sum amount would have been $263,284, or the monthly payments would have been $1,309 for the remainder of his lifetime. In the event he had died December 31, 2007 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $786 for up to 15 years. If Mr. Byrne had died December 31, 2007 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Mood, the lump sum amount would have been $84,476, or the monthly payments would have been $667 for the remainder of his lifetime. In the event he had died December 31, 2007 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $400 for up to 15 years. If Mr. Mood had died December 31, 2007 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

Executive Deferred Compensation Plan

The SCANA Corporation Executive Deferred Compensation Plan is described in the narrative following the 2007 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 a participant’s death, disability, retirement or other termination of employment. Such payments are made in the form of a single sum cash distribution. However, at the election of the participant, payments payable after the participant’s death after reaching retirement age, retirement, or termination of employment as a result of disability, may be made in the form of annual installment payments over a period not to exceed 15 years. The plan defines “retirement age” as the later of reaching age 55 and 20 years of vesting service or attainment of age 65, and defines “retirement” as termination of employment after reaching retirement age. All amounts credited to a participant’s special ledger account continue to be hypothetically invested among the investment alternatives until such amounts are paid in full to the participant or his or her beneficiary. The terms of the plan governing distributions and deferrals are subject to further modification to conform to the requirements of Section 409A of the Internal Revenue Code.

The “Aggregate Balance at Last FYE” column of the 2007 Nonqualified Deferred Compensation Table shows the amounts that would have been payable under the Executive Deferred Compensation Plan to each of our Named Executive Officers if they had died after reaching retirement age, retired, or if their employment had been terminated as a result of disability, as of December 31, 2007, and if they had been paid using the single sum form of payment. If the Named Executive Officers instead chose payment of the deferrals in annual installments, the annual installment payments over the payment periods selected by the Named Executive Officers are estimated as set forth below: Mr. Timmerman — $602,670; Mr. Addison — $73,372; Mr. Marsh — $242,824; Mr. Byrne — $103,482; and Mr. Mood — $21,947.

Discussion of Plans are Summaries Only

The discussions of our various compensation plans in this “Executive Compensation” section of 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.

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. Every other year the Nominating Committee considers relevant public data in making recommendations.

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

·   an annual retainer of $45,000 (since January 1, 2006, 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 at such times as the Board determines in cash or common stock at the director’s election.

Director Compensation and Deferral Plans

Since January 1, 2001, non-employee director compensation and related deferrals have been governed by the SCANA Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2007, the only director with funds remaining in the Voluntary Deferral Plan was Mr. Bennett.

Under the Director Compensation and Deferral Plan, a director may make an annual irrevocable election to defer the annual retainer fee, which (effective January 1, 2006) is required to be paid in SCANA common stock, in a hypothetical investment in SCANA common stock, with distribution from the plan to be ultimately payable in actual shares of SCANA common stock upon termination of the director’s service. A director also may elect to defer up to 100% of meeting attendance and conference fees with distribution from the plan to be ultimately payable in either SCANA common stock or cash. Amounts payable in SCANA common stock accrue earnings during the deferral period at our dividend rate, which directors may choose to have paid in cash when accrued or retained to invest in hypothetical shares of SCANA common stock. Amounts payable in cash accrue interest until paid. Hypothetical shares do not have voting rights.

During 2007, Messrs. Amick, Burkhardt, 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.

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

Discussion of Plans are Summaries Only

 The discussions of our various compensation plans in this “Director Compensation” section of 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.

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, 2007, the present value of the obligation under the plan was $3,677,985. The plan is funded through insurance policies on the lives of the directors. The 2007 premium for such insurance was $95,122 which was offset by the receipt of insurance proceeds in the amount of $606,609. Currently the premium estimate for 2008 is $95,122.

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.

2007 DIRECTOR COMPENSATION

The following table sets forth the compensation we paid to each of our non-employee directors in 2007.

Name (a)	Fees Earned or Paid in Cash ($) (b)	Stock Awards ($)(1) (c)	Option Awards ($) (d)	Non-Equity Incentive Plan Compensation ($) (e)	Change in Pension Value and Nonqualified Deferred Compensation Earnings(2) ($) (f)	All Other Compensation ($) (g)	Total ($) (h)
B. L. Amick	$35,500	$45,000					$80,500
J. A. Bennett	$72,000	$45,000			$5,326		$122,326
W. C. Burkhardt(3)	$19,700	$45,000					$64,700
S. A. Decker	$69,000	$45,000					$114,000
D. M. Hagood	$69,800	$45,000					$114,800
W. H. Hipp	$51,000	$45,000					$96,000
L. M. Miller	$72,000	$45,000					$117,000
M. K. Sloan	$73,800	$45,000					$118,800
H. C. Stowe	$70,300	$45,000					$115,300
G. S. York	$72,000	$45,000					$117,000

(1) The annual retainer of $45,000 is required to be paid in SCANA common stock. Shares were purchased on January 18, 2007 at a weighted average purchase price of $40.42 in order to satisfy the retainer fee obligation.

(2) Mr. Bennett is the only Director who elected to defer director fees into a cash deferral account. Pursuant to the terms of the deferral plan, the earnings are above market as defined by the Securities and Exchange Commission rules. The amounts shown above represent Mr. Bennett’s above-market earnings on his deferrals into the cash deferral account ($3,641) as well as his earnings on prior cash deferrals into the prior Voluntary Deferral Plan ($1,685).

(3)   Mr. Burkhardt retired at the Annual Meeting held on April 26, 2007.

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 2008 annual meeting of shareholders.

Equity securities issuable under SCANA's compensation plans at December 31, 2007 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	127,184		$27.45	3,210,827
Non-Employee Director Compensation Plan	n/a	n/a		94,340
Equity compensation plans not approved by security holders	n/a	n/a		n/a
Total	127,184		$27.45	3,305,167

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 22, 2008 by each director and each person named in the Summary Compensation table in Item 11. EXECUTIVE COMPENSATION.

Name of Beneficial Owner		Amount and Nature of Beneficial Ownership(1)(2)(3)(4)(5)		Percent of Class
W. B.	Timmerman	76,790		*
J. E.	Addison	17,584		*
K. B.	Marsh	25,677		*
S. A.	Byrne	14,919		*
F. P.	Mood, Jr.	4,477		*
B. L.	Amick	61,852		*
J. A.	Bennett	2,792		*
S. A.	Decker	1,781	(6)	*
D. M.	Hagood	1,541		*
W. H.	Hipp	19,584		*
L. M.	Miller	3,814		*
M. K.	Sloan	1,994		*
H. C.	Stowe	2,975		*
G. S.	York	14,374		*
All executive officers and directors as a group (16 persons)		265,393	(7)	*

*Less than 1%

(1) Includes shares purchased through February 22, 2008, 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 22, 2008, each of the following directors had acquired under the plan the number of hypothetical shares following his or her name: Messrs. Amick - 18,368; Bennett - 17,217; Hagood - 6,678; Hipp - 12,549; Sloan - 21,801; Stowe - 14,750; and York - 21,917; Mrs. Decker - 0; and Ms. Miller - 22,850.

(4) Hypothetical shares acquired under the Executive Deferred Compensation Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 22, 2008, each of the following officers had acquired under the plan the number of hypothetical shares following his name: Messrs. Timmerman - 48,020; Addison - 682; Marsh - 5,382; Byrne - 9,814; and Mood - 0.

(5) Includes shares owned by close relatives and/or shares held in trust for others, as follows: Messrs. Amick - 480; and Mood - 500.

(6) Mrs. Decker’s shares are held in a margin account with a broker and up to 30% of the shares can be pledged as collateral at any time.

(7) Includes a total of 6,768 shares subject to options that are currently exercisable or that will become exercisable within 60 days.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Related 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, 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 if any such transactions are disclosed, they are reviewed by the Nominating Committee of the Board, and if appropriate, submitted to the Board for approval. SCANA and SCE&G do not, however, have a formal written policy or procedure for approval or ratification of such transactions.

The types of transactions that have been reviewed in the past include the purchase and sale of goods, services or property from companies for which directors of SCANA and SCE&G serve as executive officers or directors, 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, and the employment of family members of executive officers or directors. There were no such transactions during the year ended December 31, 2007.

Director Independence

 Each of the directors listed in Item 10 is “independent,” as defined in the New York Stock Exchange Listing Standards and within the meaning of SCANA’s Governance Principles, except William B. Timmerman.

ITEM 14.   PRINCIPAL ACCOUNTANT 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 for the fiscal years ended December 31, 2007 and 2006 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

	SCE&G
	2007		2006
Audit Fees(1)	$	1,578,546		$	1,424,242
Audit-Related Fees(2)		73,105			42,471
Tax Fees(3)		190			58,672
Total Fees	$	1,651,841		$	1,523,385

(1) Fees for audit services billed in 2007 and 2006 consisted of audits of annual financial statements, comfort letters, statutory and regulatory audits, consents and other services related to Securities and Exchange Commission ("SEC") filings and accounting research.

(2)      Fees primarily for employee benefit plan audits for 2007 and 2006.

(3)      Fees for tax compliance and tax research services.

In 2007 and 2006, all of the Audit Fees, Audit Related Fees and Tax Fees were approved by the Audit Committee.

PART IV

ITEM 15. EXHIBITS AND 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.

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
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
2005		15,740,636		26,705,178			-		17,581,989		24,863,825
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
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
2005		8,121,122		6,038,014			-		7,830,775		6,328,361
SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
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
2005		1,182,064		3,518,845			-		3,126,840		1,574,069
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
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
2005		5,749,088		3,378,138			-		4,235,150		4,892,076

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 29, 2008

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 29, 2008

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 or consolidated affiliates thereof.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY:	/s/K. B. Marsh K. B. Marsh President and Chief Operating Officer
DATE:	February 29, 2008

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 or consolidated affiliates thereof.

/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	M. K. Sloan
	S. A. Decker	H. C. Stowe
	D. M. Hagood	G. S. York
	W. H. Hipp

*Signed on behalf of each of these persons by Francis P. Mood, Jr., Attorney-in-Fact

DATE: February 29, 2008

	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
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)
			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)

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
			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		By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein)
3.10		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	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	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	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	SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and incorporated by reference herein)
*10.02	X	X	Amendment to SCANA Executive Deferred Compensation Plan as adopted December 20, 2005 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 2006 and incorporated by reference herein)
*10.03	X	X	Amendments to SCANA Executive Deferred Compensation Plan as adopted on November 1, 2006 (Filed as Exhibit 10.03 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.04	X	X	SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by reference herein)

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
*10.05	X	X	Amendment to SCANA Director Compensation and Deferral Plan as adopted December 20, 2005 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended March 31, 2006 and incorporated by reference herein)
*10.06	X	X	Amendments to SCANA Director Compensation and Deferral Plan as adopted on November 1, 2006 (Filed as Exhibit 10.06 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.07	X	X	SCANA Supplemental Executive Retirement Plan as amended and restated as of July 1, 2000 (Filed as Exhibit 10.04 to Form 10-Q for the quarter ended September 30, 2006 and incorporated by reference herein)
*10.08	X	X	Amendments to the SCANA Supplemental Executive Retirement Plan as adopted on November 1, 2006 (Filed as Exhibit 10.08 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.09	X	X	SCANA Key Executive Severance Benefits Plan as amended and restated as of July 1, 2001 (Filed as Exhibit 10.05 to Form 10-Q for the quarter ended September 30, 2006 and incorporated by reference herein)
*10.10	X	X	Amendments to the SCANA Key Executive Severance Benefits Plan as adopted on November 1, 2006 (Filed as Exhibit 10.10 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.11	X	X	SCANA Supplementary Key Executive Severance Benefits Plan as amended and restated as of July 1, 2001 (Filed as Exhibit 10.06 to Form 10-Q for the quarter ended September 30, 2006 and incorporated by reference herein)
*10.12	X	X	Amendments to the SCANA Supplementary Key Executive Severance Benefits Plan as adopted on November 1, 2006 (Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.13	X	X	SCANA Executive Benefit Plan as established effective as of July 1, 2001 (Filed as Exhibit 10.13 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.14	X	X	Amendments to the SCANA Executive Benefit Plan as adopted on November 1, 2006 (Filed as Exhibit 10.14 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.15	X	X	SCANA Supplementary Executive Benefit Plan as established effective as of July 1, 2001 (Filed as Exhibit 10.15 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.16	X	X	Amendments to the SCANA Supplementary Executive Benefit Plan as adopted on November 1, 2006 (Filed as Exhibit 10.16 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
*10.17	X	X	SCANA Long-Term Equity Compensation Plan as amended and restated as of January 1, 2005 (Filed as Exhibit 10.01 to Form 8-K dated May 5, 2005 and incorporated by reference herein)
*10.18	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)
*10.19	X	X	SCANA Short-Term Annual Incentive Plan as amended and restated effective January 1, 2005 (Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2005 and incorporated by reference herein)

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
*10.20	X	X	Amendments to SCANA Short-Term Annual Incentive Plan as adopted on November 1, 2006 (Filed as Exhibit 10.20 to Form 10-K for the year ended December 31, 2006 and incorporated by reference herein)
10.21		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)
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