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, 2009
OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from   to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number		I.R.S. Employer Identification No.
1-8809		SCANA Corporation  (a South Carolina corporation) 100 SCANA Parkway, Cayce, South Carolina  29033 (803) 217-9000	57-0784499
1-3375		South Carolina Electric & Gas Company (a South Carolina corporation) 100 SCANA Parkway, Cayce, South Carolina  29033 (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
2009 Series A 7.70% Enhanced Junior Subordinated Notes	SCANA Corporation

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

Title of each class	Registrant
Series A Nonvoting Preferred Shares	South Carolina Electric & Gas Company

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

SCANA Corporation x South Carolina Electric & Gas Company x

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

SCANA Corporation ¨ South Carolina Electric & Gas Company ¨

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

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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

SCANA Corporation Yes o NooSouth Carolina Electric & Gas Company Yes o  Noo

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

SCANA Corporation x South Carolina Electric & Gas Company x

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

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

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

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

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

The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $3.9 billion at June 30, 2009 based on the closing price of $32.47 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, 2010
SCANA Corporation	Without Par Value	123,878,780
South Carolina Electric & Gas Company	Without 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 Proxy Statement, in connection with its 2010 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.

            South Carolina Electric & Gas Company meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and therefore is filing this Form with the reduced disclosure format allowed under General Instruction I (2).

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		Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		4
DEFINITIONS		5
PART I
Item 1.	Business	6
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	22
Item 4.	Reserved	23
Executive Officers of SCANA Corporation		24
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
	SCANA Corporation	27
	South Carolina Electric & Gas Company	81
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	124
Item 9A.	Controls and Procedures - SCANA Corporation	124
Item 9A(T).	Controls and Procedures - South Carolina Electric & Gas Company	126
Item 9B.	Other Information	126
PART III
Item 10.	Directors, Executive Officers  and Corporate Governance	127
Item 11.	Executive Compensation	127
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	127
Item 13.	Certain Relationships and Related Transactions, and Director Independence	127
Item 14.	Principal Accounting Fees and Services	127
PART IV
Item 15.	Exhibits, Financial Statement Schedules	129
SIGNATURES		131
Exhibit Index		133

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

                    adjustment;

         (2)        regulatory actions, particularly changes in rate regulation, regulations governing electric grid reliability, and

                     environmental regulations;

(3)        current and future litigation;

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

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

            interruptible markets;

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

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

            capital markets and other sources of liquidity;

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

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

            facilities of SCANA and its subsidiaries (the Company) are located and in areas served by SCANA’s subsidiaries;

(10)      payment by counterparties as and when due;

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

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

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

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

            purchased power;

(13)      the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s

            businesses;

(14)      labor disputes;

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

(16)      higher taxes;

(17)      inflation;

(18)      compliance with regulations; and

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

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

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

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

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 DEFINITIONS

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

TERM	MEANING
AER	Alternate Energy Resources, Inc.
AFC	Allowance for Funds Used During Construction
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CCP	Coal Combustion Products
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CGT	Carolina Gas Transmission Corporation
CUT	Customer Usage Tracker
CWA	Clean Water Act
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.
GHG	Greenhouse Gas
GPSC	Georgia Public Service Commission
KW or KWh	Kilowatt or Kilowatt-hour
LLC	Limited Liability Company
LNG	Liquefied Natural Gas
MACT	Maximum Achievable Control Technology
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
NERC	North American Electric Reliability Corporation
NCUC	North Carolina Utilities Commission
NMST	Negotiated Market Sales Tariff
NRC	United States Nuclear Regulatory Commission
NSR	New Source Review
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
PRP	Potentially Responsible Party
PSNC Energy	Public Service Company of North Carolina, Incorporated
RES	Renewable Energy Standard
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
SCI	SCANA Communications, Inc.
SCPSC	Public Service Commission of South Carolina
SCR	Selective Catalytic Reactor
SEC	United States Securities and Exchange Commission
SERC	SERC Reliability Corporation
SEMI	SCANA Energy Marketing, Inc.
Southern Natural	Southern Natural Gas Company
Summer Station	V. C. Summer Nuclear Station
Transco	Transcontinental Gas Pipeline Corporation
Williams Station	A.M. Williams Generating Station, owned by GENCO
WNA	Weather Normalization Adjustment

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PART I

ITEM 1.  BUSINESS

CORPORATE STRUCTURE

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

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

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

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

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

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

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

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

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

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

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

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ORGANIZATION

SCANA is a South Carolina corporation created in 1984 as a holding company.  SCANA holds, directly or indirectly, all of the capital stock of each of its subsidiaries.  SCANA and its subsidiaries had full-time, permanent employees as of February 20, 2010 and 2009 of 5,828 and 5,786, 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, 2010 and 2009 of 3,108 and 3,086, respectively.

INVESTOR INFORMATION

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

SEGMENTS OF BUSINESS

For information with respect to major segments of business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 12).  All such information is incorporated herein by reference.

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

Regulated Utilities

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 655,000 customers and the purchase, sale and transportation of natural gas to approximately 310,000 customers (each as of December 31, 2009).  SCE&G’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements.  SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina.  The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers more than 25,000 square miles.  More than 3.2 million persons live in the counties where SCE&G conducts its business.  Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies.  Predominant industries served by SCE&G include chemicals, educational services, textile manufacturing, paper products, food products, lumber and wood products, health services, food and retail stores.

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 approximately 473,000 residential, commercial and industrial customers (as of December 31, 2009).  PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina.  The industrial customers of PSNC Energy include manufacturers and processors of automobiles, pharmaceuticals, biotechnicals, chemicals, ceramics, food products, steel and non-woven textile and kindred products.

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

Nonregulated Businesses

SEMI markets natural gas primarily in the southeast and provides energy-related risk management services.  SCANA Energy, a division of SEMI, sells natural gas to over 455,000 customers (as of December 31, 2009) in Georgia’s natural gas market.  The Georgia Public Service Commission (GPSC) has selected SCANA Energy to serve as the state’s regulated provider until August 31, 2011.  Included in the above customer count, SCANA Energy serves over 90,000 customers (as of December 31, 2009) under this regulated provider contract, which includes low-income and high credit risk customers.  SCANA Energy’s total customer base represents an approximately 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.

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

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

COMPETITION

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

CAPITAL REQUIREMENTS

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

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

During the period 2010-2012, SCANA and SCE&G expect to meet capital requirements through internally generated funds, issuance of equity and short-term and long-term borrowings.  SCANA and SCE&G expect that they have or can obtain adequate sources of financing to meet their projected cash requirements for the next 12 months and for the foreseeable future.

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

SCANA’s ratios of earnings to fixed charges were 2.84, 3.04, 3.03, 2.94 and 2.19 for the years ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively.  SCE&G’s ratios of earnings to fixed charges were 3.25, 3.51, 3.40, 3.32 and 2.26 for the same periods.  SCANA’s and SCE&G’s ratios for 2005 were negatively impacted by large amounts of accelerated depreciation that were recorded under an accounting methodology approved by the Public Service Commission of South Carolina (SCPSC), and because the calculations necessarily exclude the related and fully offsetting synthetic fuel 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 2008 and 2009 were as follows:

Customer Classification	2008			2009
Residential		42	%		43	%
Commercial		31	%		32	%
Industrial		17	%		16	%
Sales for resale		7	%		6	%
Other		2	%		2	%
Total Territorial		99	%		99	%
NMST		1	%		1	%
Total		100	%		100	%

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SCE&G’s margins earned from the sale of electricity by customer classification as a percent of electric margin for 2008 and 2009 were as follows:

Customer Classification	2008			2009
Residential		48	%		49	%
Commercial		33	%		33	%
Industrial		14	%		13	%
Sales for resale		2	%		2	%
Other		2	%		2	%
Total Territorial		99	%		99	%
NMST		1	%		1	%
Total		100	%		100	%

Sales for resale include sales to six municipalities.  Sales under NMST during 2009 include sales to nine investor-owned utilities or registered marketers, three electric cooperatives and three federal/state electric agencies.  During 2008 sales under the NMST included sales to 13 investor-owned utilities or registered marketers, four electric cooperatives and four federal/state electric agencies.

 During 2009 SCE&G recorded a net increase of approximately 5,200 electric customers (growth rate of 0.8%), increasing its total electric customers to approximately 655,000 at year end.

For the period 2010-2012, SCE&G projects total territorial KWh sales of electricity to increase 1.4% annually (assuming normal weather), total electric customer base to increase 2.1% annually and territorial peak load (summer, in MW) to increase 1.7% annually.  While SCE&G’s goal is to maintain a reserve margin of between 12% and 18%, weather and other factors affect territorial peak load and can cause actual generating capacity on any given day to fall below the reserve margin goal.

Electric Interconnections

SCE&G purchases all of the electric generation of GENCO’s Williams Station under a Unit Power Sales Agreement which has been approved by FERC.  Williams Station has a net generating capacity (summer rating) of 570 MW.

SCE&G’s transmission system is part of an interconnected grid extending over a large part of the southern and eastern portions of the nation.  SCE&G interconnects with Duke Energy Carolinas, Progress Energy Carolinas, and Santee Cooper.  SCE&G also interconnects with Georgia Power Company, Oglethorpe Power Corporation and the Southeastern Power Administration’s Clarks Hill Project.  SCE&G, Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Dominion Virginia Power and ALCOA Power Generating, Inc. (Yadkin Division), are members of the Virginia-Carolinas Reliability Group (VACAR), one of several geographic divisions within the SERC Reliability Corporation (SERC).  SERC is one of eight regional entities with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing reliability standards approved by NERC within the SERC region.  SERC is divided geographically into five diverse sub-regions that are identified as Central, Delta, Gateway, Southeastern and VACAR.  The regional entities and all members of NERC work to safeguard the reliability of the bulk power systems throughout North America.  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 2007-2009 follow:

	Cost of Fuel Used
	2007		2008		2009
Per million British thermal units (MMBTU):
Nuclear	$	.43	$	.45	$	.48
Coal		2.53		3.21		4.36
Gas		8.28		10.92		4.61
All Fuels (weighted average)		2.66		3.50		3.61
Per Ton:
Coal	$	62.98	$	79.26	$	108.39
Per thousand cubic feet (MCF):
Gas	$	8.67	$	11.38	$	4.81

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The sources and percentages of total MWh generation by each category of fuel for the years 2007-2009 and the estimates for the years 2010-2012 follow:

	% of Total MWh Generated
	Actual							Estimated
	2007			2008		2009		2010		2011		2012
Coal		63	%	65	%	51	%	59	%	62	%	58	%
Nuclear		21	%	18	%	18	%	23	%	20	%	20	%
Hydro		4	%	4	%	4	%	3	%	3	%	3	%
Natural Gas & Oil		12	%	13	%	27	%	14	%	14	%	18	%
Biomass		-		-		-		1	%	1	%	1	%
Total		100	%	100	%	100	%	100	%	100	%	100	%

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

As coal costs increased and gas prices decreased during 2009, SCE&G’s mix of generation dispatched shifted.

Coal is obtained through long-term supply contracts and spot market purchases.  Long-term contracts exist with 11 suppliers located in eastern Kentucky, Tennessee and West Virginia.  These contracts provide for approximately 5.6 million tons annually, which is 98% of total expected coal purchases for 2010.  Sulfur restrictions on the contract coal range from 1% to 2%. These contracts expire at various times through 2012.  Spot market purchases are expected to continue when needed or when prices are believed to be favorable.

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

SCE&G has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station Unit 1 through 2016.  The following table summarizes contract commitments for the stages of nuclear fuel assemblies:

Commitment	Contractor	Remaining Regions(a)	Expiration Date
Uranium	United States Enrichment Corporation	22-25	2016
Enrichment	United States Enrichment Corporation	22-30	2023
Fabrication	Westinghouse Electric Corporation	22	2011

(a) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time.  Region 21 was loaded

    in 2009.

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

GAS OPERATIONS

Gas Sales-Regulated

Regulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 2008 and 2009 were as follows:

	SCANA						SCE&G
Customer Classification	2008			2009			2008			2009
Residential		50.0	%		56.3	%		36.8	%		46.4	%
Commercial		29.8	%		28.3	%		30.5	%		30.3	%
Industrial		17.0	%		10.2	%		31.6	%		19.3	%
Transportation Gas		3.2	%		5.2	%		1.1	%		4.0	%
Total		100	%		100	%		100	%		100	%

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For the three-year period 2010-2012, SCANA projects total consolidated sales of regulated natural gas in DTs to increase 1.4% annually (assuming normal weather).  Annual projected increases over such period in DT sales include residential of 2.1%, commercial of 1.1% and industrial of 1.8%.

For the three-year period 2010-2012, SCE&G projects total consolidated sales of regulated natural gas in DTs to increase    1.4% annually (assuming normal weather).  Annual projected increases over such period in DT sales include residential of 0.2%, commercial of 0.3% and industrial of 3.2%.

For the three-year period 2010-2012, SCANA’s and SCE&G’s total consolidated regulated natural gas customer base is projected to increase annually 2.4% and 1.2%, respectively.  During 2009 SCANA recorded a net increase of approximately 7,700 regulated gas customers (growth rate of 1.0%), increasing its regulated gas customers to approximately 782,000.  Of this increase, SCE&G recorded a net increase of approximately 2,600 gas customers (growth rate of 0.9%), increasing its total gas customers to approximately 310,000 (as of December 31, 2009).

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 delivered to South Carolina through firm transportation agreements with Southern Natural (expiring in 2012), Transco (expiring in 2012 and 2017) and CGT (expiring in 2011 and 2012).  The maximum daily volume of gas that SCE&G is entitled to transport under these contracts is 161,144 DT from Southern Natural, 64,652 DT from Transco and 314,529 DT from CGT.  Additional natural gas volumes may be delivered to SCE&G’s system as capacity is available through interruptible transportation.  In addition, SCE&G, under contract with SEMI, is entitled to receive up to a daily contract demand of 120,000 DT 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 CGT (expiring in 2023) on a firm basis is 198,083 DT.

SCE&G purchased natural gas at an average cost of $7.01 per MCF during 2009 and $10.50 per MCF during 2008.

SCE&G was allocated 5,437 MMCF of natural gas storage capacity on Southern Natural and Transco.  Approximately 4,100 MMCF of gas were in storage on December 31, 2009.  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 1,800 MMCF (liquefied equivalent) of gas were in storage on December 31, 2009.

North Carolina

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

PSNC Energy purchased natural gas at an average cost of $6.02 per DT during 2009 compared to $10.65 per DT during 2008.

To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and LNG peaking services.  Underground natural gas storage service agreements with Dominion, Columbia Gas Transmission, Transco and Spectra Energy provide for storage capacity of approximately 13,000 MMCF.  Approximately 9,300 MMCF of gas were in storage under these agreements at December 31, 2009.  In addition, PSNC Energy’s LNG facility can store the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day.  Approximately 900 MMCF (liquefied equivalent) of gas were in storage at December 31, 2009.  LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space.  Approximately 1,100 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2009.

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.

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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 455,000 customers (as of December 31, 2009) in Georgia’s natural gas market.  SCANA Energy’s total customer base represents an approximately 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.  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 to oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including a Risk Management Officer and several 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.

REGULATION

SCANA is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters and is subject to the jurisdiction of the United States Federal Energy Regulatory Commission (FERC) as to certain acquisitions and other matters.

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

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

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

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

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act).  SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of such short-term indebtedness.  The authority to make such issuances will expire on February 5, 2012.

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/Parr Shoals	2020	Neal Shoals	2036

The current license for the Saluda project expires August 31, 2010.  SCE&G applied to FERC for relicensing of the Saluda project on August 27, 2008.  This application is currently being reviewed by FERC.  SCE&G expects a decision by FERC in August 2010.

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

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

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

RATE MATTERS

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

SCE&G’s gas rate schedules for its residential, small commercial and small industrial customers include a Weather Normalization Adjustment (WNA) approved by the SCPSC which is in effect for bills rendered for billing cycles in November through April.  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.

PSNC Energy is authorized by the NCUC to utilize a CUT, a rate decoupling mechanism that breaks the link between revenues and the amount of natural gas sold.  The CUT allows PSNC Energy to periodically adjust its base rates for residential and commercial customers based on average per customer consumption whether impacted by weather or other factors.  

In January 2010, SCE&G filed an application with SCPSC requesting a 9.52% overall increase to retail electric base rates.  If approved, the increase in rates would be phased in over three periods in July 2010, January 2011 and July 2011.  A public hearing on this matter is scheduled to begin on May 24, 2010.

In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station.   Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC.  As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009.  In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation.  Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%.  In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court.  A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set.  SCE&G cannot predict how or when the appeals will be resolved.  In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates.  In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units.  The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

Fuel Cost Recovery Procedures

In June 2009, SCE&G filed a request with the SCPSC for approval of certain demand reduction and energy efficiency programs (DSM programs).  SCE&G has requested the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM programs along with an incentive for investing in such programs.  The SCPSC has scheduled a hearing on SCE&G’s request for April 1, 2010.

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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 over-collection or under-collection from the preceding 12-month period.  The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions.  The definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, mercury and particulates.  SCE&G may request a formal proceeding at any time should circumstances dictate such a review.  In April 2009, the SCPSC approved a settlement agreement between SCE&G and the South Carolina Office of Regulatory Staff (ORS) and others, whereby SCE&G increased the fuel cost portion of its electric rates effective with the first billing cycle of May 2009.  As part of the settlement, SCE&G agreed to spread the recovery of then under- collected fuel costs over a three-year period ending April 2012.  SCE&G is allowed to collect interest on the deferred balance.

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

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

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

ENVIRONMENTAL MATTERS

Federal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management.  Developments in these areas may require that equipment and facilities be modified, supplemented or replaced.  The ultimate effect of these regulations and standards upon existing and proposed operations cannot be predicted.  For a more complete discussion of how these regulations and standards impact SCANA and SCE&G, see the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 11B to the consolidated financial statements for SCANA and SCE&G.

OTHER MATTERS

For a discussion of SCE&G’s insurance coverage for Summer Station, see Note 11A 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 (SCANA) and its subsidiaries (together, the Company), and where indicated the risk factors also relate to South Carolina Electric & Gas Company and its consolidated affiliates (SCE&G).

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

 Our energy businesses are sensitive to changes in coal, gas, oil and other commodity prices and availability. Any such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. SCE&G is able to recover the cost of fuel (including transportation) used in electric generation through retail customers' bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources. In the case of regulated natural gas operations, costs for purchased gas and pipeline capacity are recovered through retail customers' bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in gas costs may also result in lower usage by customers unable to switch to alternate fuels.  Increases in fuel costs may also result in lower usage of electricity by customers.   Furthermore, certain construction commodities such as copper and aluminum, which are used in our transmission and distribution lines and our electrical equipment, steel and concrete have experienced significant price volatility due to changes in worldwide demand.  Also, to operate our air pollution control equipment, we use significant quantities of ammonia, limestone and lime.  With mandated compliance deadlines for air pollution controls, demand for these reagents may increase and result in higher purchase costs. 

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The costs of large capital projects, such as the Company’s and SCE&G’s construction for environmental compliance and its construction of two new nuclear units, are significant and are subject to a number of risks and uncertainties that may adversely affect the cost, timing and satisfactory completion of the projects.

The Company's and SCE&G's business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects, such as projects for environmental compliance.  For example, SCE&G and the South Carolina Public Service Authority (Santee Cooper) have agreed to jointly own, design, construct and operate two new 1,117-megawatt nuclear units at SCE&G's V.C. Summer Nuclear Station (the New Units), pursuant to which they are expending substantial resources for the evaluation, development and permitting of the project, site preparation and long lead-time procurement; substantial additional resources will be required for the construction and continued operation of the plant upon receipt of requisite approvals. Achieving the intended benefits of a large capital project of this type is subject to a number of uncertainties.   For instance, the completion of projects within established budgets and timeframes is contingent upon many variables, including the obtaining of permits and licenses in a timely manner, our timely securing of labor and materials at estimated costs, our ability to finance such projects and weather.  These projects also could be adversely affected by contractor or supplier non-performance, unforeseen engineering problems or changes in project design or scope. Our ability to maintain our operations or to complete construction projects (including new baseload generation) at reasonable cost, if at all, could be adversely affected by the availability of 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), and disruptions in the transportation of fuels.  Furthermore, joint venture projects, such as the current construction of the New Units, are subject to the risk that the joint venture partner is either unable or unwilling to continue to fund its financial commitments to the projects.  To the extent that delays occur, costs are not recoverable, or we are unable to otherwise effectively manage our capital projects, our results of operations, cash flows and financial condition may be adversely affected.

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

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

The Company and SCE&G attempt to manage commodity price exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). We do not hedge the entire exposure of our operations from commodity price 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 operate under the regulatory authority of the United States government and its various regulatory agencies, including the United States Federal Energy Regulatory Commission (FERC), the United States Nuclear Regulatory Commission (NRC), the United States Securities and Exchange Commission (SEC), the Internal Revenue Service, the United States Environmental Protection Agency (EPA), and a number of others.  In addition, the Company and SCE&G are subject to regulation by agencies of the state governments of South Carolina, North Carolina and Georgia, including regulatory commissions, state environmental commissions, state employment commissions, and a number of others.  Accordingly, the Company and SCE&G must comply with extensive federal, state and local laws and regulations. Such regulation widely affects the operation of our business. The effects encompass, among many other aspects of our business, the licensing and siting of facilities, safety, reliability of our transmission system, physical and cyber security of key assets, customer conservation through demand-side management programs, information privacy, the issuance of securities and borrowing of money, financial reporting, interaction among affiliates, the payment of dividends and employment practices. Changes to these regulations are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or SCE&G’s business.

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            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 and SCE&G’s electric transmission system and nuclear operations are subject to extensive regulation and oversight from federal agencies, including the FERC and NRC.  Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve. Although we believe we have constructive relationships with our regulators, our ability to obtain rate increases that will allow us to maintain reasonable rates of return is dependent upon regulatory discretion, and there can be no assurance that we will be able to implement rate increases when sought.

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

The Company and SCE&G are presently subject to extensive federal, state and local environmental laws and regulations, including those relating to air emissions (such as reducing nitrogen oxide, sulfur dioxide, mercury emissions and particulate matter). There is a growing consensus that some form of regulation will be forthcoming at the federal, and possibly state, levels to impose limitations on greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units.  A number of bills have been introduced in Congress that would require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted.  In addition, the EPA is drafting a rule regarding the handling of coal ash and other combustion waste produced by power plants and a new mercury control rule to replace the prior Clean Air Mercury Rule.  The EPA is expected to implement MACT (maximum achievable control technology) standards for mercury and other pollutants.  Furthermore, the EPA has announced that it expects to overhaul rules governing effluent limitation standards for coal-fired power plants.

Compliance with these laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at our facilities. These expenditures have been significant in the past and are expected to increase in the future. Changes in compliance requirements or a more burdensome interpretation by governmental authorities of existing requirements may impose additional costs on us (such as additional taxes or emission allowances) or require us to incur additional capital expenditures or curtail some of our activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated portfolio renewable standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption.  Such 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.

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

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

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

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In mid-September 2008, a very severe dislocation of the commercial paper, long-term debt and equity markets occurred as concerns over bank solvency adversely affected the credit markets.  As a result, access to these capital markets was very limited.  Further, the amount of our outstanding commercial paper was significantly reduced, and the interest rates on such outstanding commercial paper significantly increased.  Although the operation of these markets has returned to normal, the Company and SCE&G cannot predict whether similar dislocations will occur in the future or their duration.

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

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

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

SCANA's leverage ratio of debt to capital was approximately 59% at December 31, 2009.  SCANA has publicly announced its desire to reduce its present leverage ratio to levels between 54% and 57%, but SCANA's ability to do so depends on a number of factors. In the future, if SCANA is not able to reduce its leverage ratio, and maintain it within the desired range, SCANA's and SCE&G’s debt ratings may be affected, they may be required to pay higher interest rates on their long- and short-term indebtedness, and their access to the capital markets may be limited.

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

Standard & Poor's Ratings Services (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) rate SCANA's long-term senior unsecured debt at BBB, Baa2 and BBB+, respectively.  These ratings agencies rate SCANA’s junior subordinated debt (Hybrid) securities at BBB-, Baa3 and BBB-, respectively.  S&P, Moody's and Fitch rate SCE&G's long-term senior secured debt at A-, A3 and A, respectively.  S&P, Moody’s and Fitch rate the long-term senior unsecured debt of Public Service Company of North Carolina, Incorporated (PSNC Energy) at BBB+, A3 and A-, respectively.  Moody’s carries a negative outlook on each of its ratings.  S&P and Fitch carry a stable outlook on each of their ratings.  If S&P, Moody's or Fitch were to downgrade any of these long-term ratings, particularly to below investment grade, borrowing costs would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease.  Should the ratings on the hybrid securities at SCANA decline below investment grade, SCANA will be required to redeem such securities [IS THIS TRUE?]or take other prescribed remedial actions.  S&P, Moody's and Fitch rate the short-term debt of SCE&G and PSNC Energy at A-2, P-2 and F-2, respectively. If these short-term ratings were to decline, it could significantly limit access to sources of liquidity.

Operating results may be adversely affected by abnormal weather.

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

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

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

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

Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Some economic sectors important to our customer base may be particularly affected. Adverse events, economic or otherwise, may also affect the operations of key customers.  Such events may result in the loss of customers, changes in customer usage patterns and in the failure of customers to make timely payments to us. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally or legislative or regulatory actions.

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

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

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

 Critical processes or systems in the Company’s or SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission line failure, information systems failure or security breach, the effects of drought (including reduced water levels) on the operation of emission control or other generation equipment, and the effects of a pandemic or terrorist attack on our workforce or facilities 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 emissions credits or 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 SCANA Energy Marketing, Inc. (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.

18

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

 In 2009, the V.C. Summer Nuclear Station, operated by SCE&G, provided approximately 4.6 million MWh, or 18 % of our generation capacity, both of which figures are expected to increase if the New Units are completed. As such, SCE&G is subject to various risks of nuclear generation, which include the following:

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

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

   radioactive materials;

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

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

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

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

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

   the end of their operating lives.

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

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

 Implementation of our strategic plan and growth strategy requires that we attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate 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.  Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance.

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

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

19

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

        Not Applicable 

20

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.

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

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

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

21

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	385
Wateree	Coal	Eastover, SC	1970	684
Williams(2)	Coal	Goose Creek, SC	1973	570
Cope	Coal	Cope, SC	1996	420
COGEN South(3)	Biomass/Coal	Charleston, SC	1999	90
Combined Cycle:
Urquhart(4)	Coal/Gas/Oil	Beech Island, SC	1953/2002	555
Jasper	Gas/Oil	Hardeeville, SC	2004	868
Hydro(5):
Saluda		Irmo, SC	1930	200
Fairfield Pumped Storage		Parr, SC	1978	576

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

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

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

        SCE&G’s generator.

(4)     Two combined-cycle turbines burn natural gas or fuel oil to produce 330 MW of electric generation and use exhaust

       heat to power two 65 MW turbines at the Urquhart Generating Station.  Unit 3 is a 95 MW coal-fired steam unit.

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

        an aggregate net generating capacity of 21 MW.

SCE&G owns 16 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 2009 and have aggregate net generating capacity of 348 MW.

SCE&G owns 435 substations having an aggregate transformer capacity of 28 million KVA (kilovolt-ampere).  The transmission system consists of 3,274 miles of lines, and the distribution system consists of 18,187 pole miles of overhead lines and 6,552 trench miles of underground lines.

NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES

SCE&G’s natural gas system consists of 15,922 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 per day at Charleston and 90 MMCF per day at Salley.

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

PSNC Energy’s natural gas system consists of 614 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 9,928 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.

22

ITEM 3. LEGAL PROCEEDINGS

Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2009, 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 in April 2006.  AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater.  The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2010.  The site has not been remediated, nor has a clean-up cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

SCE&G is responsible for four manufactured gas plants (MGP) sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation or monitoring under work plans approved by 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 $7.7 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates.  At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected.  PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $4.4 million, the estimated remaining liability at December 31, 2009.  PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette, and Mark Rudd and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit.  The plaintiff alleges that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications.  The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims.  SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way.  In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to easement grantors situated in Charleston County, South Carolina.  In February 2008 the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County.  In July 2008, the plaintiff’s motion to add SCI to the lawsuit as an additional defendant was granted.  Trial is not anticipated before the summer of 2010.   SCE&G and SCI will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.

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

ITEM 4. RESERVED

23

EXECUTIVE OFFICERS OF SCANA CORPORATION

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

Name	Age	Positions Held During Past Five Years	Dates
William B. Timmerman	63	Chairman of the Board, President and Chief Executive Officer	*-present
Jimmy E. Addison	49	Senior Vice President and Chief Financial Officer Vice President-Finance	2006-present *-2006
George J. Bullwinkel	61	President and Chief Operating Officer-SEMI, SCI and ServiceCare	*-present
Sarena D. Burch	52	Senior Vice President-Fuel Procurement and Asset Management-SCE&G and PSNC Energy Senior Vice President-Fuel Procurement and Asset Management-South Carolina Pipeline Corporation, predecessor to CGT	*-present *-2006
Stephen A. Byrne	50	Executive Vice President-Generation, Nuclear and Fossil Hydro-SCE&G Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G	2009-present *-2009
Paul V. Fant	56	President and Chief Operating Officer-CGT Senior Vice President - SCANA Senior Vice President - Transmission Services – SCE&G	*-present 2008-present *-2007
Ronald T. Lindsay	59	Senior Vice President, General Counsel and Assistant Secretary Executive Vice President, General Counsel and Secretary of Bowater Incorporated, Greenville, South Carolina Senior Vice President, General Counsel and Secretary of Bowater Incorporated	2009-present 2006-2008 *-2006
Kevin B. Marsh	54	President and Chief Operating Officer - SCE&G Senior Vice President and Chief Financial Officer	2006-present *-2006
Charles B. McFadden	65	Senior Vice President-Governmental Affairs and Economic Development- SCANA Services	*-present

* Indicates position held at least since March 1, 2005.

24

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):

	2009								2008
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
High	$	38.64	$	36.39	$	32.70	$	36.89	$	40.24	$	44.06	$	41.32	$	42.70
Low	$	33.59	$	31.68	$	28.21	$	26.01	$	27.75	$	35.02	$	36.60	$	35.83

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, 2010 there were 123,878,780 shares of SCANA Common Stock outstanding which were held by approximately 31,112 shareholders of record.  For a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2009, see Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

SCANA declared quarterly dividends on its common stock of $.47 per share in 2009 and $.46 per share in 2008.  On February 11, 2010, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.475 per share, an increase of 1.1%.  The new dividend is payable April 1, 2010 to shareholders of record on March 10, 2010.  For a discussion of provisions that could limit the payment of cash dividends, see Item 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources – Financing Limits and Related Matters and Note 6 to the consolidated financial statements for SCANA.

SCE&G:

All of SCE&G’s common stock is owned by SCANA and is not traded.  During 2009 and 2008 SCE&G paid $167.8 million and $153.8 million, respectively, in cash dividends to SCANA.  For a discussion of provisions that could limit the payment of cash dividends, see Item 7.  MANAGEMENT’S 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, 2010)

		SCANA		SCE&G
Rating Agency	Outlook	Senior Unsecured	Junior Subordinated Debt	Senior Secured	Senior Unsecured	Commercial Paper
Moody’s	Negative	Baa2	Baa3	A3	Baa1	P-2
S&P	Stable	BBB	BBB-	A-	BBB+	A-2
Fitch	Stable	BBB+	BBB-	A	A-	F-2

For additional information regarding these securities, see Notes 4, and 5 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.

25

ITEM 6. SELECTED FINANCIAL DATA

	SCANA																	SCE&G
As of or for the Year Ended December 31,	2009			2008				2007			2006			2005				2009			2008				2007		2006		2005
	(Millions of dollars, except statistics and per share amounts)
Statement of Income Data
Operating Revenues	$	4,237		$	5,319		$		4,621		$	4,563		$	4,777		$		2,569		$	2,816		$	2,481		$	2,391		$	2,421
Operating Income		699			710				633			603			436				547			559			498			468			312
Other Income (Expense)		(177	)		(176	)			(153	)		(157	)		(155	)			(119	)		(122	)		(117	)		(121	)		(121	)
Preferred Stock Dividends		(9	)		(7	)			(7	)		(7	)		(7	)			(9	)		(7	)		(7	)		(7	)		(7	)
Income Before Cumulative Effect of Accounting Change (1)		348			346				320			304			320				281			273			245			230			258
Income Available to Common Shareholders (1) (2)	$	348		$	346		$		320		$	310		$	320		$		281		$	273		$	245		$	234		$	258
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions)		122.1			117.0				116.7			115.8			113.8				n/a			n/a			n/a			n/a			n/a
Basic and Diluted Earnings Per Share (1)(2)	$	2.85		$	2.95		$		2.74		$	2.68		$	2.81				n/a			n/a			n/a			n/a			n/a
Dividends Declared Per Share   of Common Stock	$	1.88		$	1.84		$		1.76		$	1.68		$	1.56				n/a			n/a			n/a			n/a			n/a
Balance Sheet Data
Utility Plant, Net	$	9,009		$	8,305		$		7,538		$	7,007		$	6,734		$		7,595		$	6,905		$	6,202		$	5,748		$	5,580
Total Assets		12,094			11,502				10,165			9,817			9,519				9,813			9,052			7,977			7,626			7,366
Total Equity	$	3,408		$	3,045		$		2,960		$	2,846		$	2,677		$		3,259		$	2,799		$	2,711		$	2,543		$	2,444
Short-term and Long-term Debt	$	4,846		$	4,698		$		3,852		$	3,711		$	3,677		$		3,430		$	3,320		$	2,593		$	2,498		$	2,456
Other Statistics
Electric:
Customers (Year-End)		654,766			649,571				639,258			623,402			609,971				654,830			649,636			639,312			623,453			610,025
Total sales (Million KWh)		23,104			24,284				24,885			24,519			25,305				23,107			24,287			24,888			24,538			25,323
Generating capability-Net MW     (Year-End)		5,611			5,695				5,749			5,749			5,808				5,611			5,695			5,749			5,749			5,808
Territorial peak demand-Net MW		4,557			4,789				4,926			4,742			4,820				4,557			4,789			4,926			4,742			4,820
Regulated Gas:
Customers, excluding transportation     (Year-End)		782,192			774,502				759,336			738,317			716,794				309,687			307,074			302,469			297,165			291,607
Sales, excluding transportation     (Thousand Therms) (3)		832,931			848,568				823,976			997,173			1,106,526				399,752			416,075			407,204			403,489			410,700
Transportation  customers (Year-End) (3)		482			474				446			430			365				130			120			115			100			97
Transportation volumes (Thousand Therms) (3)		1,388,096			1,366,675				1,369,684			852,100			707,189				217,750			64,034			27,113			24,845			20,317
Retail Gas Marketing:
Retail customers (Year-End)		455,198			459,250				484,565			482,822			479,382				n/a			n/a			n/a			n/a			n/a
Firm customer deliveries     (Thousand Therms)		347,324			356,288				340,743			335,896			379,913				n/a			n/a			n/a			n/a			n/a
Nonregulated interruptible customer   deliveries (Thousand Therms)		1,628,942			1,526,933				1,548,878			1,239,926			1,010,066				n/a			n/a			n/a			n/a			n/a

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

      propane assets of $4.7 million.

(2)   Reflects the 2006 adoption of revised accounting guidance related to share-based payments, recorded as the

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

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

      interstate pipeline company in November 2006.

26

			Page
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
		Overview	28
		Results of Operations	31
		Liquidity and Capital Resources	36
		Environmental Matters	41
		Regulatory Matters	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

27

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

                 RESULTS OF OPERATIONS

OVERVIEW

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

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

28

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

% of Revenues	2009			2008			2007
Regulated		73	%		65	%		66	%
Nonregulated		27	%		35	%		34	%
% of Income Available to Common Shareholders
Regulated		96	%		94	%		92	%
Nonregulated		4	%		6	%		8	%
% of Assets
Regulated		94	%		93	%		92	%
Nonregulated		6	%		7	%		8	%

Key Earnings Drivers and Outlook 

During 2009, the southeast continued to suffer from the effects of the recession.  At December 31, 2009 preliminary estimates of seasonally adjusted unemployment for the states in which the Company primarily provides service were 10.3% in Georgia, 11.2% in North Carolina and 12.6% in South Carolina.  These rates are significantly higher than rates at December 31, 2008.  Customer growth rates remained positive, but sluggish, throughout 2009 in most regulated business segments.  In addition, the regulated business segments continued to experience declines in customer usage.  Our nonregulated natural gas marketer in Georgia experienced a slight reduction in retail customers during the year as intense competition and economic distress continued.  The Company expects that any economic recovery will be slow in 2010, and cannot determine when or if customer growth and usage trends may return to pre-2008 levels.

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

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, 2009 SCE&G provided electricity to approximately 655,000 customers in an area covering nearly 17,000 square miles.  GENCO owns a coal-fired generating station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowance requirements.

Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers.  Embedded in the rates charged to customers is an allowed regulatory return on equity.  SCE&G’s allowed return on equity is 11.0%.  Demand for electricity is primarily affected by weather, customer growth and the economy.  SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

In 2008, SCE&G contracted with Westinghouse Electric Company LLC and Stone & Webster, Inc. for the design and construction of two 1,117-megawatt nuclear electric generating units at the site of V. C. Summer Nuclear Station (Summer Station).  SCE&G and South Carolina Public Service Authority (Santee Cooper) will be joint owners and share operating costs and generation output of the units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  The successful completion of the project would result in an increase of the Company’s utility plant in service of approximately 58% over its 2009 level.  Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.

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 In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

 In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011 or early 2012. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.

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

The EPA has publicly stated its intention to propose new federal regulations affecting the management and disposal of coal combustion products (CCP), such as ash, in 2010.  Such regulations could result in the treatment of some CCPs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.  While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

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, 2009 this segment provided natural gas to approximately 783,000 customers in areas covering 37,000 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 significant supply disruptions have not been experienced since 2005, the price of natural gas remains volatile. Due to the recession, demand for natural gas has decreased overall, resulting in significantly lower prices for this commodity in 2009.  The long-term impact of volatile gas prices and gas supply has not been determined.

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Gas Transmission

CGT operates an open access, transportation-only interstate pipeline company regulated by the United States Federal Energy Regulatory Commission (FERC).  CGT’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 CGT’s services is closely linked to demand for natural gas and is affected by the price of alternate fuels and customer growth.  CGT 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.  CGT also provides transportation services to other natural gas utilities, municipalities and county gas authorities and to industrial customers.

 Retail Gas Marketing

 SCANA Energy, a division of SEMI, comprises the retail gas marketing segment.  This segment markets natural gas to over 455,000 customers (as of December 31, 2009, and includes regulated division customers described below) throughout Georgia.  SCANA Energy’s total customer base represents an approximately 30% share of the 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 provides service to 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 SCANA Energy receives funding from the Universal Service Fund to offset some of the bad debt associated with the low-income group. SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas ends on August 31, 2011.  SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us(which is not intended as an active hyperlink; the information on the GPSC website is not part of this or any other report filed with the SEC).  Included in the above customer count, SCANA Energy’s regulated division served over 90,000 customers (as of December 31, 2009).

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

Energy Marketing

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

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

RESULTS OF OPERATIONS

	2009		2008		2007
Earnings per share	$	2.85	$	2.95	$	2.74
Cash dividends declared (per share)	$	1.88	$	1.84	$	1.76

• 2009 vs 2008 Earnings per share decreased in 2009 due to lower electric margin of $.09, lower gas margin of $.05, higher depreciation expense of $.05, lower gains on asset sales of $.05, higher interest expense of $.03, higher property taxes of $.05, dilution from additional shares outstanding of $.12 and by $.05 of other items explained in the following pages.  These items were partially offset by $.11 due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in favor of the Company, by $.18 due to lower operation and maintenance expenses and by $.12 due to increased equity allowance for funds using during construction.

• 2008 vs 2007 Earnings per share increased in 2008 due to higher electric margin of $.41 and higher gas margin of $.16.  These items were partially offset by $.11 due to higher interest expense, by $.14 due to higher operating expenses and by other items explained in the following pages.

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Pension Cost (Income)

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

Millions of dollars	2009			2008			2007
Income Statement Impact:
Reduction in employee benefit costs	$	-		$	(0.6	)	$	(2.5	)
Other income		(3.7	)		(14.6	)		(13.7	)
Balance Sheet Impact:
Increase (reduction) in capital expenditures		9.8			(0.3	)		(0.8	)
Component of amount (due to) payable from Summer Station co-owner		2.7			(0.3	)		(0.4	)
Regulatory asset		31.2			-			-
Total Pension Cost (Income)	$	40.0		$	(15.8	)	$	(17.4	)

The Company recorded significant pension income in each of 2008 and 2007.  Due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets, the Company recorded significant pension cost in 2009.  However, no contribution to the pension trust was necessary in or for 2009, nor did limitations on benefit payments apply.

Additionally, in February 2009, SCE&G was granted accounting orders by the SCPSC which allow it to mitigate a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above the level of pension income which is included in current rates for its retail electric and gas distribution regulated operations.  These costs are being deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.  See further information at Liquidity and Capital Resources and Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized.  The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income.  AFC represented approximately 9.8% of income before income taxes in 2009, 5.6% in 2008 and 3.3% in 2007.

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	2009		% Change			2008		% Change			2007
Operating revenues	$	2,140.9		(4.3	)%	$	2,236.4		14.4	%	$	1,954.1
Less: Fuel used in generation		817.6		(5.3	)%		863.6		30.4	%		662.3
Purchased power		16.8		(53.5	)%		36.1		10.4	%		32.7
Margin	$	1,306.5		(2.3	)%	$	1,336.7		6.2	%	$	1,259.1

• 2009 vs 2008 Margin decreased by $6.6 million due to lower residential and commercial usage (including the partially offsetting effects of favorable weather), by $11.9 million due to lower industrial sales, by lower off-system sales of $15.9 million.  Margin also decreased by $13.6 million due to the adoption of new, lower SCPSC-approved electric depreciation rates, the effect of which was offset within operating revenues.  The decreases were partially offset by higher residential and commercial customer growth of $6.2 million and by increases in base rates by the SCPSC under the BLRA of $10.8 million which became effective for bills rendered on or after March 29, 2009.

• 2008 vs 2007 Margin increased by $74.5 million due to increased retail electric rates that went into effect in January 2008 and by $16.6 million due to residential and commercial customer growth.  These increases were offset by $5.4 million due to lower off-system sales, by $3.5 million due to lower industrial sales and by $10.0 million in lower residential and commercial usage.

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

Classification (in thousands)	2009		% Change			2008		% Change			2007
Residential		7,893		0.8	%		7,828		0.2	%		7,814
Commercial		7,350		(1.3	)%		7,450		(0.3	)%		7,469
Industrial		5,324		(13.5	)%		6,152		(1.8	)%		6,267
Sales for resale (excluding interchange)		1,815		(1.9	)%		1,850		(11.9	)%		2,100
Other		562		(1.2	)%		569		1.1	%		563
Total territorial		22,944		(3.8	)%		23,849		(1.5	)%		24,213
Negotiated Market Sales Tariff (NMST)		160		(63.2	)%		435		(35.3	)%		672
Total		23,104		(4.9	)%		24,284		(2.4	)%		24,885

• 2009 vs 2008 Territorial sales volumes decreased by 95 MWh due to decreased average use, partially offset by favorable weather, and by 828 MWh due to lower industrial sales volumes as a result of a recessionary economy, partially offset by an increase of 76 MWh due to residential and commercial customer growth.  NMST volumes decreased due to lower regional demand.

• 2008 vs 2007 Territorial sales volumes decreased by 252 MWh due to weather and by 115 MWh due to lower industrial sales volumes as a result of a recessionary economy, partially offset by an increase of 238 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	2009		% Change			2008		% Change			2007
Operating revenues	$	948.4		(23.4	)%	$	1,238.1		12.9	%	$	1,096.4
Less: Gas purchased for resale		585.1		(34.0	)%		886.1		15.9	%		764.6
Margin	$	363.3		3.2	%	$	352.0		6.1	%	$	331.8

• 2009 vs 2008 Margin increased by $2.7 million due to SCPSC-approved increase in retail gas base rates at SCE&G which became effective with the first billing cycle of November 2008, by $3.7 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009, offset by a decrease of $3.0 million due to decreased customer usage at SCE&G.  The NCUC-approved rate increase at PSNC Energy, for services rendered on or after November 1, 2008, increased margin by $6.6 million.

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

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

Classification (in thousands)	2009		% Change			2008		% Change			2007
Residential		38,995		4.0	%		37,507		8.6	%	34,544
Commercial		27,220		(3.0	)%		28,004		5.4	%	26,573
Industrial		16,798		(13.2	)%		19,345		(9.1	)%	21,281
Transportation gas		30,845		(2.7	)%		31,698		1.7	%	31,154
Total		113,858		(2.3	)%		116,554		2.6	%	113,552

• 2009 vs 2008 Residential sales volume increased primarily due to customer growth and weather.  Commercial and industrial sales volume decreased primarily as a result of weak economic conditions.

• 2008 vs 2007 Residential, commercial and transportation gas sales volume increased primarily due to customer growth.  Industrial gas sales volume decreased primarily due to a loss of customers as a result of a recessionary economy.

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Gas Transmission

Gas Transmission is comprised of the operations of CGT.  Transportation revenue is generally based upon contracts to reserve long-term capacity and is not fully dependent upon volumes.  Gas transmission transportation revenue (including transactions with affiliates) was as follows:

Millions of dollars	2009		% Change			2008		% Change			2007
Transportation revenue	$	51.2		4.3	%	$	49.1		-	%	$	49.1

• 2009 vs 2008 Transportation revenue increased in 2009 due to additional sales of firm transportation capacity.

• 2008 vs 2007 In 2008 the transportation revenue was unchanged from 2007.

Transportation volumes totaled 111.3 million DT in 2009, 107.9 million DT in 2008 and 108.6 million DT in 2007.  Transportation volumes increased in 2009 due to increased use of natural gas-fired electric generation as a result of lower gas prices.  Transportation volumes decreased in 2008 as a result of lower gas-fired electric generation, primarily due to milder weather and a slowing economy.  

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	2009		% Change			2008		% Change			2007
Operating revenues	$	521.7		(17.4	)%	$	631.7		8.1	%	$	584.2
Net income		24.0		(26.2	)%		32.5		18.2	%		27.5

• 2009 vs 2008 Operating revenues decreased as a result of lower average retail prices and volumes.  Net income decreased due to lower margin, partially offset by lower bad debt, and the costs of a 2008 GPSC settlement related to operation of pricing plans.

• 2008 vs 2007 Operating revenues increased primarily as a result of higher average retail prices and volumes.  Net income increased primarily due to higher margin and lower bad debt expense, partially offset by the costs of a GPSC settlement.

            Delivered volumes totaled 34.7 million DT in 2009, 35.6 million DT in 2008 and 34.1 million DT in 2007.

Energy Marketing

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

Millions of dollars	2009		% Change			2008		% Change			2007
Operating revenues	$	776.9		(47.6	)%	$	1,483.8		27.1	%	$	1,167.7
Net income		3.4		78.9	%		1.9		(32.1	)%		2.8

• 2009 vs 2008 Operating revenues decreased primarily due to lower market prices.  Net income increased due to lower operating expenses, including bad debts.

• 2008 vs 2007 Operating revenues increased primarily due to higher market prices which more than offset the decrease in sales volumes.  Net income decreased due to higher operating expenses, including bad debts.

Delivered volumes totaled 162.9 million DT in 2009, 152.7 million DT in 2008 and 154.9 million DT in 2007.  Delivered volumes increased in 2009 compared to 2008 primarily as a result of increased power generation sales.  Delivered volumes decreased in 2008 compared to 2007 primarily as a result of decreased sales due to milder weather.

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Other Operating Expenses

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

Millions of dollars	2009		% Change			2008		% Change			2007
Other operation and maintenance	$	639.7		(5.2	)%	$	674.6		4.1	%	$	648.2
Depreciation and amortization		316.0		(1.0	)%		319.3		(1.3	)%		323.4
Other taxes		176.9		5.3	%		168.0		4.9	%		160.2
Total	$	1,132.6		(2.5	)%	$	1,161.9		2.7	%	$	1,131.8

• 2009 vs 2008 Other operation and maintenance expenses decreased by $9.0 million due to lower generation, transmission and distribution expenses, by $6.2 million due to lower incentive compensation and other benefits, by $12.4 million due to lower customer service expenses and general expenses, including bad debt expense, and by $2.5 million due to decreased legal expenses and settlement costs related to SCANA Energy’s settlement with GPSC in 2008.  Depreciation and amortization expense decreased by $13.6 million due to the implementation of new, lower SCPSC-approved electric depreciation rates in 2009, offset by higher depreciation expense of $9.5 million due to 2009 net property additions.  Other taxes increased primarily due to higher property taxes.

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

Other Income (Expense)

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

Millions of dollars		2009		% Change				2008		% Change				2007
Other income	$	64.5			(17.9	)%	$	78.6			(21.2	)%	$	99.8
Other expenses		(36.9	)		(11.1	)%		(41.5	)		(13.9	)%		(48.2	)
Total	$	27.6			(25.6	)%	$	37.1			(28.1	)%	$	51.6

• 2009 vs 2008 Total other income (expense) decreased $10.9 million due to decreased pension income and by $8.9 million due to gain on sale of assets in 2008.  These decreases were partially offset by an $8.7 million increase in interest income.  (See discussion under “Resolution of EIZ Tax Credit Uncertainty” below).

• 2008 vs 2007 Other income decreased by $11.7 million  and other expenses decreased by $6.7 million due to management and maintenance services no longer being provided for a non-affiliated synthetic fuel production facility.  Other revenues also decreased by $5.8 million due to income from the sale of a bankruptcy claim in 2007.

 Resolution of EIZ Tax Credit Uncertainty

SCE&G earned an Economic Impact Zone state income tax credit (EIZ credit) in 1996 based on qualifying property additions.  This EIZ credit exceeded the Company’s state tax liability for the 1996 tax year, leaving $15.3 million unused.  The Company’s attempt to carry forward the unused credit to tax years 1997 and 1998 was contested by the South Carolina Department of Revenue.  In September 2009, the South Carolina Supreme Court decided the matter in the Company’s favor.  As a result of the favorable resolution of this uncertainty, the Company recorded the refund for the previously contested EIZ credit of $15.3 million and an additional $14.3 million of interest income.

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Prior to this favorable Supreme Court decision, and pursuant to accounting guidance concerning income tax uncertainties, the value of the contested credit had not been reflected in the Company’s statement of income.  SCE&G’s practice has been to amortize EIZ credits to income over the lives of the properties that gave rise to the credits.  Accordingly, upon resolution of this prior uncertainty, the Company recorded a cumulative adjustment in the third quarter 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes.  The remainder of these EIZ credits will be amortized to income over the remaining life of the related properties that gave rise to the tax benefit, as a reduction in income taxes.  The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.

Interest Expense

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

Millions of dollars	2009		% Change			2008		% Change			2007
Interest on long-term debt, net	$	228.5		7.7	%	$	212.1		21.5	%	$	174.5
Other interest expense		5.0		(67.1	)%		15.2		(52.2	)%		31.8
Total	$	233.5		2.7	%	$	227.3		10.2	%	$	206.3

Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year.  Other interest expense decreased in each year primarily due to lower principal balances on short-term debt over the prior year.

Income Taxes

Income tax expense decreased in 2009 primarily due to the recognition of a tax benefit from the resolution of the EIZ tax credit uncertainty in favor of the Company (see discussion above at Other Income (Expense)) and due to changes in operating income.  Income taxes increased in 2008 primarily due to the recognition at SCE&G of $17.4 million in synthetic fuel tax credits in 2007 (see discussion under “Recognition of Synthetic Fuel Tax Credits” below) and due to changes in operating income.

Recognition of Synthetic Fuel Tax Credits

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

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

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

Available credits were not sufficient to fully recover the construction costs of dam remediation; therefore,  recovery of remaining costs is being sought in connection with a retail electric rate application filed with the SCPSC in January 2010.  In addition, SCE&G records non-cash carrying costs on the unrecovered investment which amounts were $5.4 million in 2009, $5.5 million in 2008 and $5.6 million in 2007.  As of December 31, 2009, remaining unrecovered costs were $75.5 million and were recorded as a regulatory asset within Utility Plant.  The Company expects these costs to be recoverable through rates.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.  The Company’s ratio of earnings to fixed charges for the year ended December 31, 2009 was 2.84.  

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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.

The Company also obtains equity from SCANA’s stock plans.  Shares of SCANA common stock are acquired on behalf of participants in SCANA’s Investor Plus Plan and Stock Purchase-Savings Plan through original issue shares, rather than on the open market.  This provided approximately $90 million of additional equity during 2009 and is expected to provide approximately $90 million annually for 2010 and forward.  Due primarily to new nuclear construction plans, the Company anticipates keeping this strategy in place for the foreseeable future.

SCANA’s leverage ratio of debt to capital was approximately 59% at December 31, 2009.  SCANA has publicly announced its desire to reduce its present leverage ratio to levels between 54% and 57%, but SCANA’s ability to do so depends on a number of factors.  In the future, if SCANA is not able to reduce its leverage ratio, and maintain it within the desired range, the Company’s debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.

Capital Expenditures

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC, were $914 million in 2009 and are estimated to be $1.1 billion in 2010.

The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2010-2012, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars	2010		2011		2012
SCE&G:
Electric Plant:
Generation (including GENCO)	$	567	$	666	$	948
Transmission		49		48		59
Distribution		142		154		184
Other		31		21		32
Nuclear Fuel		77		6		85
Gas		49		55		59
Common and other		25		18		10
Total SCE&G		940		968		1,377
Other Companies Combined		97		95		94
Total	$	1,037	$	1,063	$	1,471

The Company’s contractual cash obligations as of December 31, 2009 are summarized as follows:

Contractual Cash Obligations

	Payments due by periods
Millions of dollars		Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long- and short-term debt, including interest		$	8,860	$	712	$	1,844	$	454	$	5,850
Capital leases			7		2		5		-		-
Operating leases			54		12		27		4		11
Purchase obligations			7,752		745		3,705		2,002		1,193
Other commercial commitments			6,574		1,334		2,102		1,088		2,050
Total		$	23,247	$	2,805	$	7,683	$	3,548	$	9,104

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Included in the table above in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s estimated projected costs for the two additional units, in future dollars and excluding AFC, are summarized below.  To the extent that actual contracts were put in place by December 31, 2009, obligations arising from these contracts are included in the purchase obligations within the Contractual Cash Obligations table above.

Future Value
Millions of dollars	Prior to 2010		2010		2011		2012		2013		After 2013		Total
Total Project Cash Outlay	$	463	$	468	$	586	$	852	$	897	$	2,700	$	5,966

Also 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.

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 11F to the consolidated financial statements.

In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees.  The pension plan is adequately funded under current regulations, and no required contributions are anticipated until after 2011.  Cash payments under the health care and life insurance benefit plan were $12.0 million in 2009, and such annual payments are expected to be the same or increase up to $14 million 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 and their effects are reflected within other comprehensive income until the anticipated sales transactions occur.  See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.  At December 31, 2009, the Company had posted $0.8 million in cash collateral for such contracts.

The Company also has a legal obligation associated with the decommissioning and dismantling of Summer Station and other conditional asset retirement obligations that are not listed in the contractual cash obligations table.  See Notes 1B and 11G to the consolidated financial statements.

The Company does not have any recorded or unrecorded tax-related contingencies.

The Company anticipates that its contractual cash obligations will be met through internally generated funds, issuance of equity and the incurrence of additional short- and long-term debt.  The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and the foreseeable future.

Financing Limits and Related Matters

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

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act).  SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of short-term indebtedness.  The authority to make such issuances will expire on February 5, 2012.

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 At December 31, 2009, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed lines of credit (LOC) and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

Millions of dollars	SCANA		SCE&G			PSNC Energy
Lines of Credit:
Committed long-term (expire December 2011)
Total	$	200	$	650		$	250
LOC advances	$	-		100			-
Weighted average interest rate		-		.50	%		-
Outstanding commercial paper (270 or fewer days)	$	-		254			81
Weighted average interest rate		-		.33	%		.32	%
Letters of credit supported by LOC	$	3		.3			-
Available		197		296			169

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

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

       short-term commercial paper or LOC advances.

(b) SCE&G, Fuel Company and PSNC Energy may issue commercial paper in the amounts of up to $350 million,

   $250 million and $250 million, respectively.

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

Challenging conditions during late 2008 and early 2009 tested the Company’s liquidity and its ability to access short-term funding sources.  During this period, all of the banks in the Company’s revolving credit facilities fully funded draws requested of them.  As of December 31, 2009, the Company had borrowed $100 million from its $1.1 billion credit facilities, had approximately $335 million in commercial paper borrowings outstanding was obligated under $3 million in LOC supported letters of credit, and held approximately $162 million in cash and temporary investments.  The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.

At December 31, 2009, the Company had net available liquidity of approximately $823 million, and the Company’s revolving credit facilities are in place until December 2011.  The Company’s overall debt portfolio has a weighted average maturity of over 15 years and bears an average cost of 5.83%.  A significant portion of long-term debt, other than credit facility draws, effectively bears fixed interest rates or is swapped to fixed.  To further preserve liquidity, the Company rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

    Neither SCANA’s nor SCE&G’s Restated Articles of Incorporation limit the dividends that may be paid on its common stock.  However, SCANA’s junior subordinated indenture (relating to the hereinafter defined Hybrids) and SCE&G’s bond indenture (relating to the hereinafter defined Bonds) each contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on their respective common stock.

With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom.  At December 31, 2009, approximately $57 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

SCANA Corporation

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

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South Carolina Electric & Gas Company

SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its First Mortgage Bonds (Bonds) have been issued.  Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee.  Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued 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, 2009, the Bond Ratio was 5.18.

Financing Activities

During 2009 the Company experienced net cash inflows related to financing activities of approximately $100 million primarily due to issuances of long-term debt and common stock, partially offset by repayment of short-term debt and payment of dividends.

In December 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock representing an aggregate par value of $113.4 million.

In December 2009, SCE&G issued $150 million of First Mortgage Bonds bearing an annual interest rate of 5.50% and maturing on December 15, 2039.  Proceeds from the sale were used to finance capital expenditures and for general corporate purposes.

In November 2009, SCANA issued $150 million of Enhanced Junior Subordinated Notes (Hybrids) bearing an interest rate of 7.70% and maturing on January 30, 2065, subject to extension to January 30, 2080.  Because their structure and terms are characteristic of both debt instruments and equity securities, the rating agencies consider securities like the Hybrids to be hybrid debt instruments and give some “equity credit” to the issuers of such securities for purposes of computing leverage ratios.  The Hybrids are only subject to redemption at SCANA’s option and may be redeemed at any time, although the redemption prices payable by SCANA differ depending on the timing of the redemption and the circumstances (if any) giving rise thereto.  Proceeds from the Hybrids were used to provide SCE&G funds to redeem all of its outstanding shares of preferred stock and for general corporate purposes.

In connection with the issuance of the Hybrids, SCANA executed a Replacement Capital Covenant (RCC) in favor of the holders of certain designated debt (referred to as “covered debt”).  Under the terms of the RCC, SCANA agreed not to redeem or repurchase all or part of the Hybrids prior to the termination date of the RCC, unless it uses the proceeds of certain qualifying securities sold to non-affiliates within 180 days prior to the redemption or repurchase date.  The proceeds SCANA receives from such qualifying securities, adjusted by a predetermined factor, must exceed the redemption or repurchase price of the Hybrids.  Qualifying securities include common stock, and other securities that generally rank equal to or junior to the Hybrids and include distribution, deferral and long-dated maturity features similar to the Hybrids.  For purposes of the RCC, non-affiliates include (but are not limited to) individuals enrolled in SCANA’s dividend reinvestment plan, direct stock purchase plan and employee benefit plans.

The RCC is scheduled to terminate on the earliest to occur of the following: (a) January 30, 2035 (or later, if the maturity date of the Hybrids is extended), (b) the date on which SCANA no longer has any eligible debt which ranks senior in right of payment to the Hybrids, (c) the date on which the holders of at least a majority in principal amount of “covered debt” agree to the termination thereof or (d) the date on which the Hybrids are accelerated following an event of default with respect thereto.  SCANA’s $250 million in Medium Term Notes due April 1, 2020 were initially designated as “covered debt” under the RCC.

In September 2009, PSNC Energy entered into an agreement to issue and sell $100 million of ten-year unsecured notes.  PSNC Energy intends to issue the notes in the first quarter of 2010.

In June 2009, SCANA issued $30 million of Floating Rate Senior Notes due June 1, 2034.  This final installment of notes, together with notes in the same series previously issued in 2007 and 2008, represents total borrowings in the series of $110 million principal amount.  Proceeds from these notes were used to finance capital expenditures and for general corporate purposes. 

In March 2009, SCE&G issued $175 million of First Mortgage Bonds bearing an annual interest rate of 6.05% and maturing on January 15, 2038.  Proceeds from the sale were used to repay short-term debt and for general corporate purposes.

In January 2009, SCANA closed on the sale of 2.875 million shares of common stock at $35.50 per share.  Proceeds of $100.5 million were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.  In addition, SCANA issued stock valued at $91.1 million (when issued) during the twelve months ended December 31, 2009 through various compensation and dividend reinvestment plans.

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

In February 2010, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.475 per share, an increase of 1.1% from the prior declared dividend.  The dividend declared in February is payable April 1, 2010 to shareholders of record on March 10, 2010.

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ENVIRONMENTAL MATTERS

The Company’s regulated operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes.  Applicable statutes and rules include the Clean Air Act, as amended (CAA), the Clean Air Interstate Rule (CAIR), the Clean Water Act (CWA), 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, 2009, the Company’s capital expenditures for environmental control totaled $585.1 million.  These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $41.5 million during 2009, $44.0 million during 2008, and $34.4 million during 2007.  It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $13.1 million for 2010 and $48.4 million for the four-year period 2011-2014.  These expenditures are included in the Company’s Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.

On June 26, 2009, the United States House of Representatives narrowly passed energy legislation that would mandate significant reductions in greenhouse gas (GHG) emissions and require electric utilities to generate an increasing percentage of their power from renewable sources.  The bill would require, among other things, that GHG emissions be reduced to 17% below 2005 levels by 2020, and to 83% below 2005 levels by 2050.  Companies could meet these standards either through emission reductions or by obtaining emission allowances (Cap and Trade).  The bill also would impose a renewable energy standard (RES) on the total generation of electric utilities beginning at 6% in 2012 and increasing to 20% by 2020.  New nuclear generation would be excluded from the RES total generation baseline calculation, and one quarter of the RES mandate could be met through energy efficiency measures.  The United States Senate is also considering legislation that would address GHG emissions and would establish an RES.  The Company cannot predict if or when the legislation described above will become law or what requirements would be imposed on the Company by such legislation.  The Company expects that any costs incurred to comply with such legislation would be recoverable through rates.

At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2009.  The Company cannot predict whether such legislation will be introduced or enacted in 2010, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.

Air Quality

With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, SCANA, SCE&G and GENCO are subject to certain climate-related financial risks, including those involving regulatory requirements responsive to GHG emissions, as well as those involving physical impacts which could arise from global climate change.  Certain other business and financial risks arising from such climate change could also arise.  The Company cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact the Company, and the following discussion should not be considered all-inclusive.

From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions.  SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants.  Further, SCE&G has announced plans to construct two new nuclear generating plants which are expected to significantly reduce GHG emission levels once they are completed and dispatched, potentially displacing some of the current coal-fired generation sources.

See also the discussion of the court action on the CAIR below.  Even while the rule has been in flux, the Company has continued with its scrubber and selective catalytic reactor (SCR) construction projects with the expectation that new rules will be forthcoming.  

In 2005, the EPA issued the CAIR which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances.  On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it.  Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements.  SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction.   SCE&G also is installing a wet limestone scrubber at Wateree Station.  The Company expects to incur capital expenditures totaling approximately $559 million

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through 2010 for these scrubber projects, of which approximately $435 million has already been spent.   The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

Physical effects associated with climate changes could include the impact of possible changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to the Company’s electric system, as well as impacts on customers and on the Company’s supply chain and many others.  Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms.  To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties and also collects funds from customers for its storm damage reserve (see Note 1 to the consolidated financial statements).  As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams, and applicable personnel participate in ongoing training and related simulations in advance of such storms, all in order to allow the Company to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.

 In December 2009 the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA.  The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA.  The EPA has committed to issue new rules regulating such emissions by November 2011.  On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as SCE&G’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions.  The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

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

The EPA is conducting an enforcement initiative against the utilities industry related to the new source review provisions and the new source performance standards of the CAA.  As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the United States Department of Justice (DOJ), on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.

           To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether the Company will be affected by the initiative in the future. The Company believes that any enforcement action relative to its compliance with the CAA would be without merit.  The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with New Source Review (NSR).

Water Quality

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

 Hazardous and Solid Wastes

The EPA has publicly stated its intention to propose new federal regulations affecting the management and disposal of coal combustion products (CCP), such as ash, in 2010.  Such regulations could result in the treatment of some CCPs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.  While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

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The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998.  The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available.  SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the United States Department of Energy (DOE) in 1983.  As of December 31, 2009, the federal government has not accepted any spent fuel from Summer Station or any other nuclear generating facility, and it remains unclear when the repository may become available.  SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available.

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

Electric Operations

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List in April 2006.  AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater.  The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection.  The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2010.  The site has not been remediated nor has a clean-up cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.  Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

Gas Distribution

SCE&G is responsible for four decommissioned manufactured gas plant (MGP) sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control (DHEC).  SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $7.7 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates.  At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

PSNC Energy is responsible for environmental clean up at five sites in North Carolina on which MGP residuals are present or suspected.  PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs.  PSNC Energy has recorded a liability and associated regulatory asset of $4.4 million, the estimated remaining liability at December 31, 2009.  PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

REGULATORY MATTERS

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

South Carolina Electric & Gas Company

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

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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.

Natural gas distribution companies may 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.

Effective February 12, 2010 the Pipeline and Hazardous Materials Safety Administration issued a final rule establishing integrity management requirements for gas distribution pipeline systems, similar to those for transmission pipelines discussed below.  The rule gives SCE&G until August 2, 2011 to develop and implement a program for compliance with the rule.  SCE&G has not determined what impact the rule will have on its operations.  SCE&G believes that any additional cost incurred to comply with the rule will be recoverable through rates.

Public Service Company of North Carolina, Incorporated

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

The Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directed 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, 63 miles are located within these areas.  Through December 2009, PSNC Energy has assessed 95 percent of the pipeline and is required to complete its assessment of the remainder by December 2012.  Depending on the assessment method used, PSNC Energy will be required to reinspect these same miles of pipeline approximately every seven years.  PSNC Energy currently estimates the total cost through December 2012 to be $8.0 million for the initial assessments, not including any subsequent remediation that may be required.  Costs totaling $2.3 million are being recovered through rates over a three-year period beginning November 1, 2008.  The NCUC has authorized continuation of deferral accounting for certain expenses incurred to comply with DOT’s pipeline integrity management requirements until resolution of PSNC Energy’s next general rate proceeding.

Carolina Gas Transmission Corporation

CGT has approximately 73 miles of transmission line that are covered by the Integrity Management Rule of the Pipeline Safety Act.  CGT currently estimates the total cost to be $8.3 million for the initial assessments and any subsequent remediation required through December 2012.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Utility Regulation

SCANA’s regulated utilities record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities.  In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria of accounting for rate-regulated utilities, 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 and SCE&G’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded.  See Note 1B to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

 The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market.  If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded.  As of December 31, 2009, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $2.8 billion and $1.0 billion, 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

44

reading of their meters.  Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization or other regulatory provisions of rate structures.  The accrual of unbilled revenues in this manner properly matches revenues and related costs.  Accounts receivable included unbilled revenues of $187.2 million at December 31, 2009 and $185.1 million at December 31, 2008, compared to total revenues of $4.2 billion and $5.3 billion for the years 2009 and 2008, respectively.

Nuclear Decommissioning

Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future.  Among the factors that could change 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 thereon, 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.

Accounting for Pensions and Other Postretirement Benefits

The Company recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance.  The Company’s plan is adequately funded under current regulations.  Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded.  Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets.  Net pension cost of $40.0 million recorded in 2009 reflects the use of a 6.45% discount rate, derived using a cash flow matching technique, and an assumed 8.50% long-term rate of return on plan assets.  The Company believes that these assumptions were, and that the resulting pension cost amount was, reasonable.  For purposes of comparison, using a discount rate of 6.20% in 2009 would have increased the Company’s pension cost by $1.1 million.  Had the assumed long-term rate of return on assets been 8.25%, the Company’s pension cost for 2009 would have increased by $1.5 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 or derives them from modeling techniques that incorporate market data.  Only a small portion of assets are valued using less transparent (so-called “Level 3”) methods.

In developing the expected long-term rate of return assumptions, the Company evaluates historical performance, targeted allocation amounts and expected payment terms.   As of the beginning of 2009, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 4.0%, 9.0%, 9.2% and 10.6%, respectively.  The 2009 expected long-term rate of return of 8.5% was based on a target asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.  For 2010, the expected rate of return is also 8.5%.

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

45

The pension trust is adequately funded under current regulations, and no contributions have been required since 1997. Management does not anticipate the need to make pension contributions until after 2011.

The Company accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan.  This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense.  The Company used a discount rate of 6.45%, derived using a cash flow matching technique, and recorded a net cost of $17.7 million for 2009.  Had the selected discount rate been 6.20%, the expense for 2009 would have been $0.1 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

The Company accrues for the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation in accordance with applicable accounting guidance.  The obligations are recognized at fair value in the period in which they are incurred, and associated asset retirement costs are capitalized as a part of the carrying amount of the related long-lived assets.  Because such obligations relate primarily to the Company’s regulated utility operations, their recording has no significant impact on results of operations.  As of December 31, 2009, the Company has recorded an asset retirement obligation (ARO) of $111 million for nuclear plant decommissioning (as discussed above) and an ARO of $366 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines.  All of the amounts recorded in accordance with the relevant accounting guidance are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.  Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Transactions

Although SCANA invests in securities and business ventures, it does not hold significant investments in unconsolidated special purpose 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 11 to the consolidated financial statements.

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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 represent quoted market prices.  Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.

	Expected Maturity Date
December 31, 2009 Millions of dollars	2010	2011	2012	2013	2014	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	14.8	719.3	265.5	157.9	42.5	3,102.7.	4,302.7	4,538.3
Average Fixed Interest Rate (%)	6.87	5.91	6.23	7.05	4.88	6.05	6.07
Variable Rate ($)	4.4	4.4	4.4	4.4	4.4	159.4	181.1	161.0
Average Variable Interest Rate (%)	.96	.96	.96	.96	.96	.67	.70
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	303.2	253.2				559.6	1.1
Pay Interest Rate (%)	3.44	6.01	4.93				5.51
Receive Interest Rate (%)	8.75	6.89	6.28				6.63
Pay Fixed/Receive Variable ($)	4.4	4.4	4.4	4.4	4.4	159.4	181.4	(10.1	)
Average Pay Interest Rate (%)	6.17	6.17	6.17	6.17	6.17	4.88	5.04
Average Receive Interest Rate (%)	.96	.96	.96	.96	.96	.67	.70

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

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 $34 million at December 31, 2009 and $37 million at December 31, 2008, which amounts do not have a stated interest rate associated with them.

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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 Call	Sold Put
2010	Long		(Long)	(Short)	(Short)	(Long)
Settlement Price (a)	5.65	Strike Price (a)	7.07	5.43	9.59	5.43
Contract Amount (b)	9.7	Contract Amount (b)	46.9	1.3	3.5	1.3
Fair Value (b)	9.8	Fair Value (b)	1.5	0.2	-	(0.2	)
2011
Settlement Price (a)	6.69	Strike Price (a)	8.15	-	-	-
Contract Amount (b)	0.6	Contract Amount (b)	0.1	-	-	-
Fair Value (b)	0.6	Fair Value (b)	-	-	-	-
(a) Weighted average, in dollars
(b)Millions of dollars

Swaps	2010	2011	2012	2013
Commodity Swaps:
Pay fixed/receive variable (b)	82.1	20.2	7.2	3.7
Average pay rate (a)	6.2457	7.0328	7.2548	7.8450
Average received rate (a)	5.7101	6.4252	6.5319	6.6778
Fair Value (b)	75.1	18.5	6.5	3.1
Pay variable/receive fixed (b)	33.9	10.7	3.0	-
Average pay rate (a)	5.7237	6.4174	6.5134	-
Average received rate (a)	5.9601	6.7629	6.6998	-
Fair Value (b)	35.3	11.2	3.1	-
Basis Swaps:
Pay variable/receive variable (b)	44.4	7.5	4.0	3.2
Average pay rate (a)	5.7524	6.4643	6.5966	6.7678
Average received rate (a)	5.8017	6.4447	6.5408	6.6978
Fair Value (b)	44.8	7.5	4.0	3.1
(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 information above includes those financial positions of Energy Marketing, SCE&G and PSNC Energy.

SCE&G and PSNC Energy utilize futures, options and swaps to hedge gas purchasing activities.  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 SCE&G’s hedging activities are to be included in the PGA.  As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation.  The offset to the change in fair value of these derivatives is deferred.  PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred.  PSNC Energy defers premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program for subsequent recovery from customers.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

SCANA Corporation

Cayce, South Carolina

We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2009 and 2008, and the related consolidated statements of income, changes in common equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009.  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 the 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, 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 March 1, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 1, 2010

49

SCANA Corporation

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2009			2008
Assets
Utility Plant In Service	$	10,835		$	10,433
Accumulated Depreciation and Amortization		(3,302	)		(3,146	)
Construction Work in Progress		1,149			711
Nuclear Fuel, Net of Accumulated Amortization		97			77
Acquisition Adjustments		230			230
Utility Plant, Net		9,009			8,305
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $107 and $94		291			194
Assets held in trust, net-nuclear decommissioning		67			54
Other investments		73			68
Nonutility Property and Investments, Net		431			316
Current Assets:
Cash and cash equivalents		162			272
Receivables, net of allowance for uncollectible accounts of $9 and $11		694			828
Inventories (at average cost):
Fuel		376			358
Materials and supplies		115			108
Emission allowances		10			15
Prepayments and other		164			232
Deferred income taxes		-			23
Total Current Assets		1,521			1,836
Deferred Debits and Other Assets:
Regulatory assets		985			905
Other		148			140
Total Deferred Debits and Other Assets		1,133			1,045
Total	$	12,094		$	11,502

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December 31, (Millions of dollars)	2009		2008
Capitalization and Liabilities
Common equity	$	3,408	$	3,045
Preferred stock		-		113
Long-Term Debt, Net		4,483		4,361
Total Capitalization		7,891		7,519
Current Liabilities:
Short-term borrowings		335		80
Current portion of long-term debt		28		144
Accounts payable		428		405
Customer deposits and customer prepayments		103		97
Taxes accrued		134		128
Interest accrued		71		69
Dividends declared		59		56
Other		98		176
Total Current Liabilities		1,256		1,155
Deferred Credits and Other Liabilities:
Deferred income taxes, net		1,122		1,009
Deferred investment tax credits		111		103
Asset retirement obligations		477		458
Pension and other postretirement benefits		229		261
Regulatory liabilities		879		838
Other		129		159
Total Deferred Credits and Other Liabilities		2,947		2,828
Commitments and Contingencies (Note 11)		-		-
Total	$	12,094	$	11,502

See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, (Millions of dollars, except per share amounts)	2009			2008			2007
Operating Revenues:
Electric	$	2,141		$	2,236		$	1,954
Gas-regulated		958			1,247			1,105
Gas-nonregulated		1,138			1,836			1,562
Total Operating Revenues		4,237			5,319			4,621
Operating Expenses:
Fuel used in electric generation		818			864			662
Purchased power		17			36			33
Gas purchased for resale		1,570			2,547			2,161
Other operation and maintenance		640			675			648
Depreciation and amortization		316			319			324
Other taxes		177			168			160
Total Operating Expenses		3,538			4,609			3,988
Operating Income		699			710			633
Other Income (Expense):
Other income		65			79			99
Other expenses		(37	)		(42	)		(48	)
Interest charges, net of allowance for borrowed funds used during construction of $23, $16 and $13		(233	)		(227	)		(206	)
Allowance for equity funds used during construction		28			14			2
Total Other Expense		(177	)		(176	)		(153	)
Income Before Income Tax Expense and Earnings (Losses) from Equity Method   Investments		522			534			480
Income Tax Expense		167			189			140
Income Before Earnings (Losses) from Equity Method Investments		355			345			340
Earnings (Losses) from Equity Method Investments		2			8			(13	)
Net Income		357			353			327
Less Preferred Stock Dividends of Subsidiary		(9	)		(7	)		(7	)
Income available to Common Shareholders of SCANA Corporation	$	348		$	346		$	320
Basic and Diluted Earnings Per Share	$	2.85		$	2.95		$	2.74
Weighted Average Common Shares Outstanding (Millions)		122.1			117.0			116.7
Dividends Declared Per Share of Common Stock	$	1.88		$	1.84		$	1.76

See Notes to Consolidated Financial Statements.

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 SCANA Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2009			2008			2007
Cash Flows From Operating Activities:
Net Income	$	357		$	353		$	327
Adjustments to reconcile net income to net cash provided from operating activities:
Excess losses (earnings) from equity method investments, net of distributions		1			2			14
Depreciation and amortization		329			327			330
Amortization of nuclear fuel		18			17			19
Allowance for equity funds used during construction		(28	)		(14	)		(2	)
Carrying cost recovery		(5	)		(5	)		(6	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables		134			(21	)		17
Inventories		(76	)		(114	)		(41	)
Prepayments and other		64			(103	)		(23	)
Other regulatory assets		(82	)		(23	)		40
Deferred income taxes, net		93			76			22
Regulatory liabilities		(6	)		(13	)		94
Accounts payable		(46	)		(14	)		(38	)
Taxes accrued		6			(28	)		35
Interest accrued		2			18			-
Changes in other assets		(36	)		(3	)		4
Changes in other liabilities		(46	)		(1	)		(62	)
Net Cash Provided From Operating Activities		679			454			730
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(787	)		(833	)		(712	)
Proceeds from investments and sale of assets		31			19			10
Nonutility property additions		(127	)		(71	)		(13	)
Investments		(6	)		(2	)		(10	)
Net Cash Used For Investing Activities		(889	)		(887	)		(725	)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock		191			42			6
Proceeds from issuance of debt		600			1,526			40
Repayments of debt		(599	)		(231	)		(34	)
Redemption/repurchase of equity securities		(113	)		-			(14	)
Dividends		(234	)		(219	)		(210	)
Short-term borrowings, net		255			(547	)		140
Net Cash Provided From (Used For) Financing Activities		100			571			(72	)
Net Increase (Decrease) in Cash and Cash Equivalents		(110	)		138			(67	)
Cash and Cash Equivalents, January 1		272			134			201
Cash and Cash Equivalents, December 31	$	162		$	272		$	134
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $23, $16 and $13)	$	233		$	196		$	172
-Income taxes		79			121			76
Noncash Investing and Financing Activities:
Accrued construction expenditures		160			92			82

See Notes to Consolidated Financial Statements. 

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 SCANA Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME

									Accumulated
									Other
	Common Stock					Retained			Comprehensive
Millions	Shares		Amount			Earnings			Income (Loss)			Total
Balance as of December 31, 2006	117	$	1,411		$	1,464		$	(29	)	$	2,846
Comprehensive Income :
Income Available to Common Shareholders of SCANA Corporation						320						320
Other Comprehensive Income, net of taxes $3									7			7
Total Comprehensive Income						320			7			327
Issuance of Common Stock Upon Exercise of Options			9			(3	)					6
Repurchase of Common Stock			(13	)								(13	)
Dividends Declared on Common Stock						(206	)					(206	)
Balance as of December 31, 2007	117		1,407			1,575			(22	)		2,960
Comprehensive Income (Loss):
Income Available to Common Shareholders of SCANA Corporation						346						346
Other Comprehensive Loss, net of taxes $(53)									(87	)		(87	)
Total Comprehensive Income (Loss)						346			(87	)		259
Issuance of Common Stock	1		42									42
Dividends Declared on Common Stock						(216	)					(216	)
Balance as of December 31, 2008	118		1,449			1,705			(109	)		3,045
Comprehensive Income:
Income Available to Common Shareholders of SCANA Corporation						348						348
Other Comprehensive Income, net of taxes $33									54			54
Total Comprehensive Income						348			54			402
Issuance of Common Stock	5		191									191
Dividends Declared on Common Stock						(230	)					(230	)
Balance as of December 31, 2009	123	$	1,640		$	1,823		$	(55	)	$	3,408

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Organization and Principles of Consolidation

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

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

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

The Company reports certain investments using the cost or equity method of accounting, as appropriate.  Intercompany balances and transactions have been eliminated in consolidation with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable as permitted by accounting guidance.

B.      Basis of Accounting

The Company’s cost-based rate-regulated utilities 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 regulatory assets and regulatory liabilities, summarized as follows.

	December 31,
Millions of dollars	2009		2008
Regulatory Assets:
Accumulated deferred income taxes	$	173	$	171
Under-collections–electric fuel adjustment clause		55		-
Environmental remediation costs		26		27
Asset retirement obligations and related funding		279		265
Franchise agreements		50		50
Deferred employee benefit plan costs		325		345
Planned major maintenance		5		-
Other		72		47
Total Regulatory Assets	$	985	$	905

Regulatory Liabilities:
Accumulated deferred income taxes	$	30	$	32
Other asset removal costs		733		688
Storm damage reserve		44		48
Planned major maintenance		-		11
Monetization of bankruptcy claim		40		43
Other		32		16
Total Regulatory Liabilities	$	879	$	838

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

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            Under-collections–electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings which are expected to be recovered in retail electric rates during the period January 2011 through April 2012.  As a part of a settlement agreement approved by the SCPSC in April 2009, SCE&G is allowed to collect interest on the deferred balance during the recovery period.

Environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company.  Costs incurred at sites owned by SCE&G are being recovered through rates, of which $19.4 million, net of insurance recovery, remain to be recovered. SCE&G is authorized to amortize $1.4 million of these costs annually.  At sites owned by PSNC Energy, costs of $2.1 million are being recovered through rates over a period ending October 2011.  In addition, management believes that estimated remaining costs of $4.4 million, will be recoverable 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.

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 employee benefit plan costs represent amountsof pension and other postretirement benefit costs which were accrued as liabilities, and costs deferred pursuant to specific regulatory orders (See Note 3), but which are expected to be recovered through utility rates.

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates.  SCE&G applied costs of $10.0 million in 2009 and $7.3 million in 2008 to the reserve.  See Note 2.

Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved through specific SCPSC orders.  SCE&G is collecting $8.5 million annually, ending December 2013, through electric rates to offset turbine maintenance expenditures.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

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

The SCPSC or the North Carolina Utilities Commission (NCUC) (collectively, state commissions) or the United States Federal Energy Regulatory Commission (FERC) have reviewed and approved through specific orders most of the items shown as regulatory assets.  Other regulatory assets include certain costs which have not been approved for recovery by a state commission or by FERC.  In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company.  In addition, the Company hasdeferred in utility plant in service approximately $75.5 million of unrecovered costs related to the Lake Murray backup dam project and $70.1 million of costs related to the installation of selective catalytic reactor (SCR) technology at its Cope Station generating facility.  See Note 11B.  These costs are not currently being recovered, but are expected to be recovered through rates in future periods.  In the future, as a result of deregulation or other changes in the regulatory environment, or changes in accounting requirements the Company 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.

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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, 2009 and 2008 (including amounts capitalized related to the recording of AROs).  Accumulated depreciation associated with SCE&G’s share of Summer Station was $538.3 million and $527.6 million as of December 31, 2009 and 2008, respectively (including amounts capitalized related to the recording of AROs).  SCE&G’s share of the direct expenses associated with operating Summer Station is included in other operation and maintenance expenses and totaled $92.7 million in 2009, $87.4 million in 2008 and $86.7 million in 2007.

In addition, SCE&G and Santee Cooper are constructing two new nuclear units at the site of Summer Station that will be jointly owned in the proportions of 55 percent and 45 percent, respectively, with each party providing its own financing.  SCE&G will be the operator of the new units.  SCE&G’s portion of the construction work in progress for the new units was $476.5 million at December 31, 2009 and $126.7 million at December 31, 2008.

         Planned major maintenance costs related to certain fossil and hydro turbine equipment and nuclear refueling outages are accrued in periods other than when 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.  Through 2013, SCE&G is authorized to collect $8.5 million annually through electric rates to offset turbine maintenance expenditures.  For the year ended December 31, 2009, SCE&G incurred $17.1 million for turbine maintenance.  Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset 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 $1.1 million per month from January 2007 through June 2008 for its portion of the outage in the spring of 2008 and accrued $1.2 million per month from July 2008 through December 2009 for its portion of the outage in the fall of 2009.  Total costs for the 2008 outage were $25.7 million, of which SCE&G was responsible for $17.1 million.  Total costs for the 2009 outage were $32.7 million, of which SCE&G was responsible for $21.8 million.  As of December 31, 2008, SCE&G had an accrued balance of $7.3 million.  There was no accrued balance as of December 31, 2009.

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 7.5% for 2009, 6.3% for 2008 and 6.2% for 2007.  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 $187.2 million at December 31, 2009 and $185.1 million at December 31, 2008.

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

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

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

PSNC Energy is authorized by the NCUC to utilize a customer usage tracker (CUT), a rate decoupling mechanism that breaks the link between revenues and the amount of natural gas sold.  The CUT allows PSNC Energy to periodically adjust its base rates for residential and commercial customers based on average per customer consumption whether impacted by weather or other factors.  

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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:

	2009		2008		2007
SCE&G	2.97	%	3.18	%	3.16	%
GENCO	2.66	%	2.66	%	2.66	%
CGT	1.94	%	1.92	%	2.00	%
PSNC Energy	3.10	%	3.06	%	3.28	%
Aggregate of Above	2.95	%	3.11	%	3.12	%

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

The Company considers amounts categorized by FERC as “acquisition adjustments” to be goodwill.  The carrying value of these amounts are $210 million recorded by PSNC Energy (Gas Distribution segment) and $20 million recorded by CGT (Gas Transmission segment).  The Company performs annual impairment evaluations on these acquisition adjustments.  No impairment charges have resulted from such evaluations during any period presented.  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 2009, 2008 and 2007) 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 thereon, 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.

Taxes that are billed to and collected from customers are recorded 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 within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues.  For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.

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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 fair value and adjusts fair value each reporting period.  The Company determines fair value of most of the energy-related derivatives contracts using quotations that reference actively traded contracts.  For other derivatives contracts, the Company uses published market surveys and, in certain cases, brokers to obtain quotes concerning fair value. Market quotes tend to be more plentiful for those derivatives contracts maturing in two years or less. See Note 9.

M.     New Accounting Matters

Effective for the year ended December 31, 2009, the Company adopted accounting guidance that requires enhanced disclosures about an employer’s plan assets in a defined benefit pension plan or other postretirement plan.  The required disclosures include a discussion of the inputs and evaluation techniques used to develop fair value measurements of plan assets.  In addition, the fair value of each major category of plan assets is required to be disclosed separately for pension plans and other postretirement benefit plans.  The adoption of this guidance did not affect the Company’s results of operations, cash flows or financial position.

 Effective June 30, 2009, the Company adopted new accounting guidance that makes the Company’s management responsible for subsequent-events accounting and disclosure.  The adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.  

Effective January 1, 2009, the Company adopted accounting guidance that requires enhanced disclosures about an entity’s derivative and hedging activities to include how derivative instruments are accounted for and the effect of such activities on the entity’s financial statements.  The adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.  

Effective January 1, 2009, the Company adopted accounting guidance thatrequires entities to report noncontrolling (minority) interests in subsidiaries as equity.  The adoption of this guidancedid not significantly impact the Company’s results of operations, cash flows or financial position.  

Effective January 1, 2009, the Company adopted accounting guidance thatrequires the acquiring entity in a business combination to recognize the assets acquired and the liabilities assumed at their fair values at the acquisition date and to disclose all of the information needed to evaluate and understand the nature and financial effect of the business combination.  The adoption of this guidancedid not impact the Company’s results of operations, cash flows or financial position.

N.      Earnings Per Share

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

O.      Affiliated Transactions

The Company received cash distributions from equity-method investees of $3.3 million in 2009, $6.2 million in 2008 and $7.8 million in 2007.  The Company made investments in equity-method investees of $1.6 million in 2009, $2.2 million in 2008 and $16.2 million in 2007.

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SCE&G purchases shaft horsepower from a cogeneration facility.  The facility is owned by a limited liability company (LLC) in which, prior to July 1, 2008, SCANA held an equity-method investment.  Transactions subsequent to June 30, 2008 are not considered to be affiliated transactions.  SCE&G made affiliated purchases of shaft horsepower from the LLC of $14.7 million in 2008 and $27.7 million in 2007.

SCE&G held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel.  The partnerships ceased operations as a result of the expiration of the synthetic fuel tax credit program at the end of 2007, and they were dissolved in 2008.  SCE&G purchased synthetic fuel from these affiliated companies of $281.6 million in 2007.  The Company made cash investments in these affiliated companies of $2.2 million in 2008 and $16.2 million in 2007.

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.

Q.      Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  At December 31, 2009, such counterparties held 49% of PSNC Energy’s natural gas inventory, with a carrying value of $26.0 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, 2011.

R.      Preferred Stock

The Company has corrected the presentation of certain preferred stock to present these preferred securities in a manner consistent with temporary equity.  Although the effects are not material to previously issued balance sheets, the presentation of these amounts has been corrected as of December 31, 2008 by presenting these $106 million of preferred securities separately from common equity and eliminating the “Shareholders’ Investment” section and related total.  This change had no impact on income, earnings per share, or on cash flows for any period presented.

2.       RATE AND OTHER REGULATORY MATTERS

SCE&G

Electric

SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.  In April 2009, the SCPSC approved a settlement agreement between SCE&G, the South Carolina Office of Regulatory Staff (ORS), and others authorizing SCE&G to increase the fuel cost portion of its electric rates, effective with the first billing cycle of May 2009.  As a part of the settlement, SCE&G agreed to spread the recovery of undercollected fuel costs over a three-year period ending April 2012, as further described in Note 1B.  SCE&G is allowed to collect interest on the deferred balance.

In January 2010, SCE&G filed an application with the SCPSC requesting a 9.52% overall increase to retail electric base rates.  If approved, the increase in rates would be phased in over three periods in July 2010, January 2011 and July 2011.  A public hearing on this matter is scheduled to begin on May 24, 2010.

In December 2009, SCE&G submitted to the FERC for filing revised tariff sheets to change the network and point to point transmission rates under SCE&G’s Open Access Transmission Tariff.  The request, if approved, would result in an annual revenue increase of $5.6 million.   The requested rates utilize a cost of service formula, which departs from the traditional rate structure currently in effect.

In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the Base Load Review Act (the BLRA) to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station.  The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.  The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.  

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In June 2009, SCE&G filed a request with the SCPSC for approval of the implementation of certain demand reduction and energy efficiency programs (DSM programs).  SCE&G has requested the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM programs, along with an incentive for investing in such programs.  The SCPSC has scheduled a hearing on SCE&G’s request for April 1, 2010.

 In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL).  This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008.  In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review.  Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011 or early 2012.  This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.

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

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.  In more recent actions, the SCPSC also approved SCE&G’s request to apply against the reserve certain tree trimming expenditures in excess of amounts included in base rates through 2010.

Gas

The Natural Gas Rate Stabilization Act (RSA) 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 infrastructure.  In October 2009, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $13 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle of November 2009.

In October 2008, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $3.7 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle of November 2008.

In October 2007, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $4.6 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle in November 2007.

SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities.  SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average.  In December 2009, in connection with the annual review of the PGA and the gas purchasing policies of SCE&G, the SCPSC determined that SCE&G’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 17 months ended July 31, 2009.  

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PSNC Energy

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

 In October 2009, in connection with PSNC Energy’s 2009 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, 2009.

In September 2009, the NCUC approved PSNC Energy’s semi-annual rate adjustment under the CUT.  The CUT allows PSNC Energy to adjust its base rates for residential and commercial customers based on average per customer consumption.  As a result of this rate adjustment, increases for residential and commercial customers are in effect for service rendered on and after October 1, 2009.  The previous semi-annual rate adjustment under the CUT, which was effective for service rendered from April 1 through September 30, 2009, resulted in rate decreases for these customers.  

In October 2008, the NCUC granted PSNC Energy an annual increase in natural gas margin revenues of approximately $9.1 million, offset by an $8.4 million reduction in fixed gas costs, for a net annual increase in rates and charges to customers of approximately $0.7 million.   The new rates were effective for services rendered on or after November 1, 2008.

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.

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	2009			2008			2009			2008
Benefit obligation, January 1	$	709.5		$	704.8		$	192.5		$	196.8
Service cost		15.5			15.1			3.6			4.0
Interest cost		44.8			43.2			12.3			12.0
Plan participants’ contributions		-			-			2.9			2.7
Actuarial (gain) loss		54.5			(12.2	)		14.1			(9.2	)
Benefits paid		(34.9	)		(41.4	)		(15.0	)		(13.8	)
Benefit obligation, December 31	$	789.4		$	709.5		$	210.4		$	192.5

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The actuarial (gain) loss is primarily attributable to revisions to the annual discount rate assumption detailed below.

The accumulated benefit obligation for retirement benefits was $747.2 million at the end of 2009 and $674.6 million at the end of 2008.  The accumulated retirement benefit obligation differs from the projected retirement benefit obligation above in that it reflects no assumptions about future compensation levels.

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

					Other
	Pension				Postretirement
	Benefits				Benefits
	2009		2008		2009			2008
Annual discount rate used to determine benefit obligation	5.75	%	6.45	%		5.90	%		6.45	%
Assumed annual rate of future salary increases for projected benefit obligation	4.00	%	4.00	%		4.00	%		4.00	%

An 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2010.  The rate was assumed to decrease gradually to 5.0% for 2017 and to remain at that level thereafter.

A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at each of December 31, 2009 and December 31, 2008 by $1.9 million.  A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at each of December 31, 2009 and December 31, 2008 by $1.7 million.

Funded Status

Millions of Dollars	Pension Benefits						Other Postretirement Benefits
December 31,	2009			2008			2009			2008
Fair value of plan assets	$	758.9		$	629.4			-			-
Benefit obligations		789.4			709.5		$	210.4		$	192.5
Funded status (liability)	$	(30.5	)	$	(80.1	)	$	(210.4	)	$	(192.5	)

Amounts recognized on the consolidated balance sheets consist of:

Millions of Dollars	Pension Benefits						Other Postretirement Benefits
December 31,	2009			2008			2009			2008
Current liability		-			-		$	(12.0	)	$	(11.6	)
Noncurrent liability	$	(30.5	)	$	(80.1	)		(198.4	)		(180.9	)

Amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2009 and 2008 were as follows:

Millions of Dollars		Pension Benefits				Other Postretirement Benefits
December 31,		2009		2008		2009		2008
Net actuarial loss	$	35.5	$	49.6	$	1.4	$	0.7
Prior service cost		0.7		0.8		0.2		0.3
Transition obligation		-		-		0.4		0.5
Total	$	36.2	$	50.4	$	2.0	$	1.5

In connection with the joint ownership of Summer Station, as of December 31, 2009 and 2008, the Company recorded within deferred debits $11.2 million and $12.1 million, respectively, attributable to Santee Cooper’s one-third portion of shared pension costs.  As of December 31, 2009 and 2008, the Company also recorded within deferred debits $10.2 million and $9.3 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.

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Changes in Fair Value of Plan Assets

	Pension Benefits
Millions of dollars	2009			2008
Fair value of plan assets, January 1	$	629.4		$	929.5
Actual return on plan assets		164.4			(258.7	)
Benefits paid		(34.9	)		(41.4	)
Fair value of plan assets, December 31	$	758.9		$	629.4

Investment Policies and Strategies

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 periods presented did not include SCANA common stock.

The Company’s pension plan asset allocation at December 31, 2009 and 2008 and the target allocation for 2010 are as follows:

	Percentage of Plan Assets
	Target Allocation		At December 31,
Asset Category	2010		2009		2008
Equity Securities		65%		66%		61%
Debt Securities		35%		34%		39%

For 2010, the expected long-term rate of return on assets will be 8.5%.  In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, and assumes an asset allocation of 65% with equity managers and 35% with fixed income managers.  Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.

Fair Value Measurements

Assets held by the pension plan are measured at fair value as described below.  Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  At December 31, 2009, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

				Fair Value Measurements at Reporting
				Date Using
				Quoted Market Prices		Significant		Significant
				in Active Market for		Other		Other
				Identical		Observable		Observable
		December 31,		Assets/Liabilities		Inputs		Inputs
Millions of dollars		2009		(Level 1)		(Level 2)		(Level 3)
Common stock	$	329	$	329
Mutual funds		70		22	$	48
Short-term investment vehicles		37				37
US Treasury securities		68				68
Corporate debt securities		64				64
Loans secured by mortgages		9				9
Other-municipals		2				2
Common collective trusts		166				166
Multi-strategy hedge funds		14					$	14
	$	759	$	351	$	394	$	14

The Plan values common stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded.  Preferred stock is generally valued based on recently executed transactions.  Other mutual funds and common collective trusts are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes.  Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities.  US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or

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spreads or benchmarked thereto.  Corporate debt securities are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments.  Hedge funds are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis.  The valuation of the multi-strategy hedge fund of funds is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value.  The estimated fair value is the price at which redemptions and subscriptions occur.

A reconciliation of Level 3 assets is as follows:

		Fair Value Measurements Using
		Significant Unobservable Inputs
Millions of dollars		(Level 3)
Beginning Balance	$	-
Unrealized gains or losses included in changes in net assets		-
Purchases, issuances, and settlements		14
Transfers in or out of Level 3		-
Ending Balance	$	14

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:

Expected Benefit Payments			Other Postretirement Benefits*
Millions of dollars	Pension Benefits		Excluding Medicare Subsidy		Including Medicare Subsidy		.
2010	$	55.9	$	12.6	$	12.4
2011		65.3		12.9		12.7
2012		64.1		13.2		13.0
2013		63.5		13.6		13.4
2014		62.0		14.2		14.0
2015-2019		323.9		77.6		76.7

* Net of participant contributions

Pension Plan Contributions

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

Net Periodic Benefit Cost (Income)

The Company records net periodic benefit cost (income) utilizing beginning of the year assumptions.  Disclosures required for these plans are set forth in the following tables.

Components of Net Periodic Benefit Cost (Income)

	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2009			2008			2007			2009		2008		2007
Service cost	$	15.5		$	15.1		$	15.3		$	3.7	$	4.0	$	4.4
Interest cost		44.9			43.2			40.5			12.3		12.0		11.7
Expected return on assets		(50.8	)		(81.1	)		(79.8	)		n/a		n/a		n/a
Prior service cost amortization		7.0			7.0			6.6			1.0		1.0		1.1
Amortization of actuarial losses		23.4			-			-			-		-		0.9
Transition amount amortization		-			-			-			0.7		0.7		(0.2	)
Net periodic benefit cost (income)	$	40.0		$	(15.8	)	$	(17.4	)	$	17.7	$	17.7	$	17.9

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Additionally, in February 2009, SCE&G was granted accounting orders by the SCPSC which allow it to mitigate a significant portion of increased pension cost by deferring as a regulatory asset the amount of pension expense above that which is included in current rates for its retail electric and gas distribution regulated operations.  These costs are being deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.  

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

	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2009			2008			2007			2009			2008			2007
Current year actuarial (gain)/loss	$	(10.4	)	$	42.1		$	0.9		$	0.7		$	(0.7	)	$	(0.9	)
Amortization of actuarial losses		(3.7	)		-			-			-			-			(0.1	)
Current year prior service cost		-			-			0.1			-			-			-
Amortization of prior service cost		(0.1	)		(0.1	)		(0.1	)		(0.1	)		(0.1	)		(0.2	)
Amortization of transition obligation		-			-			-			(0.1	)		(0.1	)		-
Total recognized in other comprehensive income	$	(14.2	)	$	42.0		$	0.9		$	0.5		$	(0.9	)	$	(1.2	)

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

	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009		2008			2007
Discount rate		6.45	%		6.25	%		5.85	%	6.45	%		6.30	%		5.85	%
Expected return on plan assets		8.50	%		9.00	%		9.00	%	n/a			n/a			n/a
Rate of compensation increase		4.00	%		4.00	%		4.00	%	4.00	%		4.00	%		4.00	%
Health care cost trend rate		n/a			n/a			n/a		8.00	%		9.00	%		9.50	%
Ultimate health care cost trend rate		n/a			n/a			n/a		5.00	%		5.00	%		5.00	%
Year achieved		n/a			n/a			n/a		2015			2014			2013

The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2010 are as follows:

				Other
		Pension		Postretirement
Millions of Dollars		Benefits		Benefits
Actuarial (gain)/loss	$	4.3		-
Prior service (credit)/cost		0.1	$	0.1
Transition obligation		-		0.1
Total	$	4.4	$	0.2

Other postretirement benefit costs are subject to annual per capita limits pursuant to plan design.  As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $100,000.

Stock Purchase Savings Plan

The Company also sponsors a defined contribution plan in which eligible employees may participate.  Eligible employees may defer up to 25% of eligible earnings subject to certain limits and may diversify their investments.  Employee deferrals are fully vested and nonforfeitable at all times.  The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings.  Total matching contributions made to the plan for 2009, 2008 and 2007 were $21.0 million, $20.5 million and $19.1 million, respectively.  These matching contributions were made in the form of SCANA common stock.

Share-Based Compensation

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

        Compensation costs related to share-based payment transactions are required to be recognized in the financial statements. With limited exceptions, including those liability awards discussed below, 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.

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Liability Awards

The 2007-2009 performance cycle provides for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle.  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 the performance shares.  Payout of performance share awards was 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%).  Accordingly, payouts under the 2007 three-year cycle were earned for each year that performance goals were met during the three-year cycle, though payments were deferred until the end of the cycle and were contingent upon the participant still being employed by the Company at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability.   Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2010.

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

In the 2009-2011 performance cycle, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash.  The remaining 80% of the awards were made in performance shares with payment criteria identical to those awarded for the 2008-2010 performance cycle.

    Compensation cost of all these liability awards is recognized over their respective three-year performance periods 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 related to similar prior programs were paid totaling $9.1 million in 2009 and $2.6 million in 2008.  No such payments were made in 2007.

Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $7.2 million in 2009, $17.2 million in 2008 and $6.6 million in 2007.  Fair value adjustments resulted in capitalized compensation costs of $0.9 million in 2009, $1.9 million in 2008 and $0.7 million in 2007.

Equity Awards

A summary of activity related to nonvested shares follows:

		Weighted Average
		Grant-Date
Nonvested Shares	Shares	Fair Value
Nonvested at January 1, 2008	-	$	-
Granted	75,824		37.33
Forfeited	1,236		37.35
Nonvested at December 31, 2008	74,588		37.33
Forfeited	2,399		37.33
Nonvested at December 31, 2009	72,189		37.33

Nonvested shares were granted at a price corresponding to the opening price of SCANA common stock on the date of the grant.  The Company expensed compensation costs for nonvested shares of $0.7 million in 2009 and $0.8 million in 2008 and recognized related tax benefits of $0.3 million 2009 and 2008.  The Company capitalized compensation costs of $0.1 million in 2009 and 2008.

As of December 31, 2009 there was $0.9 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements under the Plan.  The cost is expected to be recognized in 2010.  No shares were granted under the plan in 2009, and none were vested in any year presented.

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A summary of activity related to nonqualified stock options follows:

Stock Options	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2006		385,940		$	27.56
Exercised		(258,756	)		27.62
Outstanding-December 31, 2007		127,184			27.45
Exercised		(20,720	)		27.49
Outstanding-December 31, 2008		106,464			27.44
Exercised		(2,875	)		27.50
Outstanding-December 31, 2009		103,589			27.44

No stock options have been granted since August 2002, and all options were fully vested in August 2005.  No options were forfeited during any period presented.  The options expire ten years after the grant date.  At December 31, 2009, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 1.9 years.

The exercise of stock options during 2009 was satisfied using original issue shares, and during 2007 and 2008 such exercise was satisfied using a combination of original issue shares and open market purchases of the Company’s common stock.  For the years ended December 31, 2009 and 2008, cash realized upon the exercise of options and related tax benefits were not significant.  For the year ended December 31, 2007, cash realized upon the exercise of options totaled $7.1 million, and related tax benefits credited to additional paid in capital (common equity) during the period totaled $1.5 million.

 4.      LONG-TERM DEBT

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

			2009					2008
Dollars in millions	Maturity		Balance		Rate			Balance		Rate
Medium-Term Notes (unsecured) (a)	2011-2020	$	950		6.51	%	$	950		6.51	%
Senior Notes (unsecured) (b)	2034		110		6.47	%		80		6.47	%
First Mortgage Bonds (secured)	2011-2039		2,560		6.03	%		2,335		6.07	%
Junior Subordinated Notes (unsecured) (c)	2065		150		7.70	%		-		-
GENCO Notes (secured)	2011-2024		272		5.93	%		276		5.95	%
Industrial and Pollution Control Bonds (d)	2012-2038		228		4.63	%		228		4.63	%
Senior Debentures (e)	2012-2026		110		7.35	%		113		7.39	%
Borrowings Under Credit Agreements	2011		100		.50	%		456		1.67	%
Fair value of interest rate swaps (f)			8					12
Other	2010-2027		38					69
Total debt			4,526					4,519
Current maturities of long-term debt			(28	)				(144	)
Unamortized discount			(15	)				(14	)
Total long-term debt, net		$	4,483				$	4,361

(a)    Includes fixed rate debt hedged by variable interest rate swaps of $550 million in 2009.

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

(c)    May be extended through 2080.

(d)    Includes $71.4 million of variable rate debt hedged by fixed rate swaps.

(e) Includes fixed rate debt hedged by a variable interest rate swap of $9.6 million in 2009 and $12.8 million in 2008. 

(f) Includes unamortized payments received to terminate previous swaps designated as fair value hedges.  See Note 9.

The annual amounts of long-term debt maturities for the years 2010 through 2014 are summarized as follows:

Year	Millions of dollars
2010	$	28
2011		732
2012		277
2013		169
2014		50

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

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5.      LINES OF CREDIT AND SHORT-TERM BORROWINGS

 At December 31, 2009 and 2008, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed lines of credit (LOC) and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

		SCANA			SCE&G (b)							PSNC Energy (b)
Millions of dollars		2009	2008				2009			2008		2009		2008
Lines of credit:
Committed long-term (expire December 2011)
Total	$	200	$	200		$	650		$	650		$	250		$	250
LOC advances	$	-		15			100			285			-			156
Weighted average interest rate		-		2.17	%		.50	%		1.61	%		-			1.72	%
Outstanding commercial paper    (270 or fewer days) (a)	$	-		-			254			34			81			46
Weighted average interest rate		-		-			.33	%		5.69	%		.32	%		6.15	%
Letters of credit supported by LOC	$	3		-			.3			-			-			-
Available		197		185			296			331			169			48

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

           liquidity support. Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by

           Fuel Company of short-term commercial paper or LOC advances.

(b)        SCE&G, Fuel Company and PSNC Energy operate commercial paper programs in the maximum amounts of

           $350 million, $250 million and $250 million, respectively.

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

The South Carolina Jobs-Economic Development Authority (JEDA) issued $35.0 million of Industrial Revenue Bonds in December 2008, the proceeds of which were loaned to SCE&G.  The payment of the principal and interest on the bonds is secured by a letter of credit issued by Branch Banking and Trust Company.  The bonds mature on December 1, 2038.  The letter of credit expires on December 10, 2011.  Similarly, JEDA issued $36.4 million of Industrial Revenue Bonds in November 2008, the proceeds of which were loaned to GENCO and guaranteed by SCANA.  The bonds mature on December 1, 2038.  The payment of the principal and interest on these bonds is secured by a letter of credit issued by Branch Banking and Trust Company.  The letter of credit expires on November 9, 2011.

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

6.       COMMON EQUITY

Neither SCANA’s nor SCE&G’s Restated Articles of Incorporation limit the dividends that may be paid on their common stock.  However, SCE&G’s bond indenture contains 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, 2009, approximately $57 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

Cash dividends on SCANA’s common stock were declared during 2009, 2008 and 2007 at an annual rate per share of $1.88, $1.84 and $1.76, respectively.

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

Millions of Dollars	2009			2008
Net unrealized losses on cash flow hedging activities, net of taxes of $10 and $35	$	(17	)	$	(57	)
Net unrealized deferred costs of employee benefit plans, net of taxes of $24 and $32		(38	)		(52	)
Total	$	(55	)	$	(109	)

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The Company recognized losses of $66.9 million, $14.3 million and $19.1 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2009, 2008 and 2007, respectively.  

 On January 7, 2009, SCANA closed on the sale of 2.875 million shares of common stock at $35.50 per share.  Net proceeds of $100.5 million were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.  In addition, SCANA issued common stock valued at $91.1 million (when issued) during the year ended December 31, 2009 through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan.

7.         PREFERRED STOCK

            On December 30, 2009, SCE&G redeemed all outstanding shares of its preferred stock.  The fair value of the preferred shares redeemed exceeded their carrying value by approximately $2.1 million.  This excess payment is reflected on the statement of income as a return to preferred shareholders within preferred dividends of subsidiary.

8.       INCOME TAXES

Total income tax expense attributable to income for 2009, 2008 and 2007 is as follows:

Millions of dollars	2009			2008			2007
Current taxes:
Federal	$	63		$	56		$	101
State		(6	)		6			13
Total current taxes		57			62			114
Deferred taxes, net:
Federal		94			114			23
State		8			14			4
Total deferred taxes		102			128			27
Investment tax credits:
Deferred-state		20			5			5
Amortization of amounts deferred-state		(9	)		(3	)		(3	)
Amortization of amounts deferred-federal		(3	)		(3	)		(3	)
Total investment tax credits		8			(1	)		(1	)
Total income tax expense	$	167		$	189		$	140

The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows:

Millions of dollars	2009			2008			2007
Income	$	348		$	346		$	320
Income tax expense		167			189			140
Preferred stock dividends		9			7			7
Total pre-tax income	$	524		$	542		$	467
Income taxes on above at statutory federal income tax rate	$	183		$	190		$	163
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		8			15			12
Allowance for equity funds used during construction		(10	)		(5	)		(1	)
Synthetic fuel tax credits		-			-			(17	)
Deductible dividends-Stock Purchase Savings Plan		(8	)		(7	)		(7	)
Amortization of federal investment tax credits		(3	)		(3	)		(3	)
Domestic production activities deduction		(4	)		(1	)		(4	)
Other differences, net		1			-			(3	)
Total income tax expense	$	167		$	189		$	140

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The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $1,123 million at December 31, 2009 and $986 million at December 31, 2008 are as follows:

Millions of dollars	2009		2008
Deferred tax assets:
Nondeductible reserves	$	99	$	95
Nuclear decommissioning		42		40
Financial instruments		11		38
Unamortized investment tax credits		54		51
Deferred compensation		24		21
Pension plan  income		-		33
Unbilled revenue		16		12
Monetization of bankruptcy claim		15		16
Other		3		18
Total deferred tax assets		264		324
Deferred tax liabilities:
Property, plant and equipment		1,169		1,067
Pension plan income		2		-
Deferred employee benefit plan costs		113		132
Deferred fuel costs		42		51
Other		61		60
Total deferred tax liabilities		1,387		1,310
Net deferred tax liability	$	1,123	$	986

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 2005 are closed for additional assessment.  With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2006.  

In September 2009, an income tax uncertainty was resolved in the Company’s favor upon the receipt of a favorable ruling in litigation of a state tax issue, which resulted in a refund of $15.3 million in state income taxes, plus interest.  While the total of this tax benefit that will impact the effective tax rate will be $15.3 million, such impact is not expected to be material in future years because, under regulatory accounting provisions, the tax benefit recorded is being amortized into earnings over the remaining life of property additions that gave rise to the tax benefit.   No other material changes in the status of the Company’s uncertain tax positions have occurred during any period presented through December 31, 2009. 

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2009, 2008 or 2007.

9.       DERIVATIVE FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  The Company recognizes changes in the fair value of derivative instruments either in earnings or 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, for interest rate swaps, discounted cash flow models with independently sourced data.

    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 for SCANA and each of its subsidiaries.  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.

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Commodity Derivatives

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.  Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as New York Mercantile Exchange (NYMEX) futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.

                     The Company’s regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options.  SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred.  The SCPSC has ruled that the results of these hedging activities are to be included in the PGA.  As such, the cost of derivatives and gains and losses on such 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 gains or losses from its hedging program in deferred accounts as a regulatory asset for the under-recovery of gas costs or as a regulatory liability for the over-recovery of gas costs.  These derivative financial instruments utilized by the Company’s regulated gas operations are not formally designated as hedges under applicable accounting guidance.

    The unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in other comprehensive income.  When the hedged transactions affect earnings, the previously deferred gains and losses are reclassified from other comprehensive income to 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. 

As an accommodation to certain customers, SCANA Energy Marketing, Inc. (SEMI), as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives.

Interest Rate Swaps

The Company uses interest rate swaps to manage interest rate risk on certain debt issuances.  These swaps are classified as either fair value hedges or cash flow hedges.  

The Company uses swaps to synthetically convert fixed rate debt to variable rate debt.  These swaps are designated as fair value hedges.  Prior to 2006, some of these swaps were terminated prior to maturity of the underlying debt instruments.  The gains on these terminated swaps are being amortized over the life of the debt they hedged.

The Company also uses swaps to synthetically convert variable rate debt to fixed rate debt.  In addition, in anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements which are designated as cash flow hedges.  The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities, and for the holding company or nonregulated subsidiaries, are recorded in other comprehensive income.  Ineffective portions of changes in fair value are recognized in income.

The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

At December 31, 2009, the Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Other Energy Management Contracts (in dekatherms)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
Cash flow	-	5,390,350	13,915,971	19,306,321
Not designated (a)	6,291,000	160,000	19,007,840	25,458,840
Total (a)	6,291,000	5,550,350	32,923,811	44,765,161

(a)  Includes an aggregate 9,961,000 dekatherms related to basis swap contracts in Retail Gas Marketing and Energy Marketing.

At December 31, 2009, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $559.6 million and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $181.4 million.

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At December 31, 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheet as follows:

	Fair Values of Derivative Instruments
		Asset Derivatives			Liability Derivatives
		Balance Sheet		Fair	Balance Sheet		Fair
Millions of dollars		Location (b)		Value	Location (b)		Value
Derivatives designated as hedging instruments
Interest rate contracts		Other deferred debits	$	5	Other deferred credits	$	14
Commodity contracts		Other current liabilities		1	Other current liabilities		7
					Other deferred credits		2
Total			$	6		$	23

Derivatives not designated as
hedging instruments
Commodity contracts	Prepayments and other	$	1
Energy management contracts	Prepayments and other		2	Other current liabilities	$	3
	Other current liabilities		2	Other deferred credits		1
	Other deferred debits		1
Total		$	6		$	4

(b)  Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses.  In the    

     Company’s consolidated balance sheet, unrealized gain and loss positions with the same counterparty are reported as

     either a net asset or liability.

The effect of derivative instruments on the statement of income for the year ended December 31, 2009 is as follows:

Derivatives in Fair Value Hedging Relationships

With regard to the Company’s interest rate swaps designated as fair value hedges, the gains on those swaps and the losses on the hedged fixed rate debt are recognized in current earnings and included in interest expense. These gains and losses, combined with the amortization of gains on those swaps that were terminated prior to 2006 as discussed above, resulted in reductions to interest expense of $6.6 million for the year ended December 31, 2009.

Derivatives in Cash Flow Hedging Relationships

		Gain or (Loss)		Gain or (Loss) Reclassified from
Derivatives in Cash Flow		Deferred in Regulatory Accounts		Deferred Accounts into Income
Hedging Relationships		(Effective Portion)		(Effective Portion)
Millions of dollars		2009		Location		Amount
Interest rate contracts	$	42		Interest expense	$	(3		)
Total	$	42			$	(3		)
		Gain or (Loss)		Gain or (Loss) Reclassified from
Derivatives in Cash Flow		Recognized in OCI, net of tax		Accumulated OCI into Income,
Hedging Relationships		(Effective Portion)		net of tax (Effective Portion)
Millions of dollars		2009		Location		Amount
Interest rate contracts	$	9		Interest expense	$	(3	)
Commodity contracts		(39	)	Gas purchased for resale		(67	)
Total	$	(30	)		$	(70	)

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As of December 31, 2009, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $3.5 million, net of tax as an increase to gas cost and approximately $3.1, net of tax as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of December 31, 2009, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2013.

Derivatives Not Designated as
Hedging Instruments	Gain or (Loss) Recognized in Income
Millions of dollars	Location		Amount
Commodity contracts	Gas purchased for resale	$	(16	)
Total		$	(16	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate derivatives designated as cash flow hedges totaled $1.2 million, net of tax, in 2009.  These amounts are recorded within interest expense on the statement of income.

Credit Risk Considerations

Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of December 31, 2009, the Company has posted $17.9 million of collateral related to derivatives with contingent provisions that are in a net liability position.  If all of the contingent features underlying these instruments were fully triggered as of December 31, 2009, the Company would be required to post an additional $6.3 million of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2009, is $24.2 million.

10.                             FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded.  For commodity derivative assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.  The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows: 

		Fair Value Measurements Using
		Quoted Prices in Active		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of December 31, 2009
Assets - Available for sale securities	$	2	$	-
Assets - Derivative instruments		1		11
Liabilities - Derivative instruments		-		30
As of December 31, 2008
Assets - Available for sale securities	$	2	$	-
Assets - Derivative instruments		9		26
Liabilities - Derivative instruments		2		138

There were no fair value measurements based on significant unobservable inputs (Level 3) for either date presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2009 and December 31, 2008 were as follows:

	December 31, 2009				December 31, 2008
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,510.9	$	4,726.0	$	4,505.6	$	4,591.7
Preferred stock		-		-		113.8		96.8

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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 as of December 31, 2008 was estimated using market quotes.  At December 31, 2009, all shares of preferred stock had been redeemed.  See additional disclosure at Note 7.

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

11.     COMMITMENTS AND CONTINGENCIES

A.      Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.6 billion.  Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year.  SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be $78.3 million per incident, but not more than $11.7 million per year. 

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited.  The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses.  Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.2 million.

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

B.      Environmental

SCE&G

 In December 2009 the United States Environmental Protection Agency (EPA) issued a final finding that atmospheric concentrations of greenhouse gasses (GHG) endanger public health and welfare within the meaning of Section 202(a) of the Clean Air Act, as amended (CAA).  The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA.  The EPA has committed to issue new rules regulating such emissions by November 2011.  On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as SCE&G’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions.  The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the Clean Air Interstate Rule (CAIR), which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances.  On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it.  Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements.  SCE&G has completed the installation of selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction.   SCE&G also is installing a wet limestone scrubber at Wateree Station.  The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these scrubber projects.   The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

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

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SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List in April 2006.  AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater.  The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection.  The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that is expected to be completed in 2010.  The site has not been remediated nor has a clean-up cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.  Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

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

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control.  SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $7.7 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates.  At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

PSNC Energy

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected.  PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs.  PSNC Energy has recorded a liability and associated regulatory asset of $4.4 million, which reflects its estimated remaining liability at December 31, 2009.  PSNC Energy expects to recover through rates any costs, allocable to PSNC Energy arising from the remediation of these sites.

C.      Claims and Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette, and Mark Rudd and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit.  The plaintiff alleges that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications.  The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims.  SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way.  In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to easement grantors situated in Charleston County, South Carolina.   In February 2008, the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County.  In July 2008, the plaintiff’s motion to add SCI to the lawsuit as an additional defendant was granted.  Trial is not anticipated before the summer of 2010.   SCE&G and SCI 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.

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

D.      Nuclear Generation

In 2008, SCE&G and Santee Cooper entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent

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of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  Assuming timely receipt of federal  approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.

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 2051.  Rent expense totaled approximately $23.7 million in 2009, $13.5 million in 2008 and $19.0 million in 2007.  Future minimum rental payments under such leases are as follows:

	Millions of dollars
2010	$	12
2011		10
2012		9
2013		8
2014		3
Thereafter		12
Total	$	54

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 $1.7 billion in 2009, $2.8 billion in 2008 and $2.3 billion in 2007.  Future payments under such purchase commitments are as follows:

	Millions of dollars
2010	$	723
2011		914
2012		1,366
2013		1,402
2014		1,088
Thereafter		2,112
Total	$	7,605

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

G.       Guarantees

 The Company issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties.  These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues.  The Company is not required to recognize a liability for guarantees issued on behalf of its subsidiaries unless it becomes probable that performance under the guarantees will be required.  The Company believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized.  To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements.  At December 31, 2009, the maximum future payments (undiscounted) that the Company could be required to make under guarantees totaled $1.3 billion.

H.     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.

The legal obligations associated with the retirement of long-lived tangible assets that results from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations.  As of December 31, 2009, the Company has recorded an ARO of approximately $111 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $366 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines.  All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

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

Millions of dollars	2009			2008
Beginning balance	$	458		$	307
Liabilities incurred		1			1
Liabilities settled		(1	)		(2	)
Accretion expense		24			17
Revisions in estimated cash flows		(5	)		135
Ending Balance	$	477		$	458

Revisions in estimated cash flows in 2008 primarily related to the expectation of higher costs associated with coal ash disposal than had been assumed in the 2007 cash flow analysis.

12.     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 CGT which operates as an open access, transportation-only pipeline company regulated by FERC.

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

All Other is comprised of 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.

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)

2009	Electric Operations		Gas Distribution		Gas Transmission		Retail Gas Marketing		Energy Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	2,141	$	948	$	10	$	522	$	616	$	27		$	(27	)	$	4,237
Intersegment Revenue		8		1		41		-		161		375			(586	)		-
Operating Income		504		132		19		n/a		n/a		-			44			699
Interest Expense		15		21		4		-		-		-			193			233
Depreciation and Amortization		244		61		7		4		-		21			(21	)		316
Income Tax Expense		-		28		6		15		2		3			113			167
Income Available to Common Shareholders		n/a		n/a		n/a		24		3		(12	)		333			348
Segment Assets		7, 312		2,040		259		183		99		946			1,255			12,094
Expenditures for Assets		817		76		10		-		1		120			(110	)		914
Deferred Tax Assets		-		10		17		8		6		2			(43	)		-

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

2007
Customer Revenue	$	1,954	$	1,096	$	9	$	584	$	978	$	29		$	(29	)	$	4,621
Intersegment Revenue		7		1		40		-		203		340			(591	)		-
Operating Income		464		111		18		n/a		n/a		-			40			633
Interest Expense		16		26		6		1		-		-			157			206
Depreciation and Amortization		258		56		7		3		-		17			(17	)		324
Income Tax Expense		3		20		8		16		2		5			86			140
Income Available to Common Shareholders		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

Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G.  As a result, SCE&G does not allocate interest charges, income tax expense or assets other than utility plant to its segments.  For nonregulated operations, management uses income available to common shareholders as the measure of segment profitability and evaluates total assets for financial position.  Interest income is not reported by segment and is not material.  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 Income Available to Common Shareholders consist of SCE&G’s unallocated income available to common shareholders of SCANA Corporation.

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

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

13.     QUARTERLY FINANCIAL DATA (UNAUDITED)

2009 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,343	$	878	$	921	$	1,095	$	4,237
Operating income		223		125		175		176		699
Income available to common shareholders		114		55		103		76		348
Basic and diluted earnings per share		.94		.45		.84		.62		2.85

2008 Millions of dollars, except per share amounts
Total operating revenues	$	1,533	$	1,218	$	1,266	$	1,302	$	5,319
Operating income		213		131		189		177		710
Income available to common shareholders		109		57		94		86		346
Basic and diluted earnings per share		.94		.48		.80		.73		2.95

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

			Page
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		81
		Overview	81
		Results of Operations	82
		Liquidity and Capital Resources	86
		Environmental Matters	89
		Regulatory Matters	92
		Critical Accounting Policies and Estimates	92
		Other Matters	94
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		95
Item 8.	Financial Statements and Supplementary Data		97
		Report of Independent Registered Public Accounting Firm	97
		Consolidated Balance Sheets	98
		Consolidated Statements of Income	100
		Consolidated Statements of Cash Flows	101
		Consolidated Statements of Changes in Equity and Comprehensive Income	102
		Notes to Consolidated Financial Statements	103

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

                OF OPERATIONS

OVERVIEW

South Carolina Electric & Gas Company (SCE&G, together with its consolidated affiliates, the Company) is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas.  SCE&G’s business is subject to seasonal fluctuations.  Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements.  SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina.  The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers more than 25,000 square miles.

Key Earnings Drivers and Outlook 

During 2009, the southeast continued to suffer under the effects of the recession.  At December 31, 2009 the preliminary estimate of seasonally adjusted unemployment for South Carolina was 12.6%, a rate significantly higher than the rate at December 31, 2008.  Customer growth remained positive, but sluggish, throughout 2009.  In addition, SCE&G continued to experience declines in customer usage.  The Company expects that any economic recovery will be slow in 2010, and cannot determine when or if customer growth and usage trends may return to pre-2008 levels.

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

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, 2009 SCE&G provided electricity to approximately 655,000 customers in an area covering nearly 17,000 square miles.  GENCO owns a coal-fired generating 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.  SCE&G’s allowed return on equity is 11.0%.  Demand for electricity is primarily affected by weather, customer growth and the economy.  SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

In 2008, SCE&G contracted with Westinghouse Electric Company LLC and Stone & Webster, Inc. for the design and construction of two 1,117-megawatt nuclear electric generating units at the site of V. C. Summer Nuclear Station (Summer Station).  SCE&G and South Carolina Public Service Authority (Santee Cooper) will be joint owners and share operating costs and generation output of the units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019.  The successful completion of the project would result in an increase of the Company’s utility plant in service of approximately 68% over its 2009 level.  Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.

 In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

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 In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011 or early 2012. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.

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

The United States Environmental Protection Agency (EPA) has publicly stated its intention to propose new federal regulations affecting the management and disposal of coal combustion products (CCP), such as ash, in 2010.  Such regulations could result in the treatment of some CCPs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.  While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

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, 2009 this segment provided natural gas to approximately 310,000 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 of 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 significant supply disruptions have not been experienced since 2005, the price of natural gas remains volatile.  Due to the recession, the demand for natural gas has decreased overall, resulting in significantly lower prices for this commodity in 2009.  The long-term impact of volatile gas prices and gas supply has not been determined.

RESULTS OF OPERATIONS

Net Income

Net income was as follows:

Millions of dollars	2009		% Change			2008		% Change			2007
Net income	$	287.5		2.0	%	$	281.9		11.6	%	$	252.5

• 2009 vs 2008 Net income increased $12.9 million due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in favor of the Company, by higher gas margin of $3.0 million, by decreased incentive compensation of $3.1 million and by decreased generation, transmission and distribution expenses of $4.6 million.  These increases to net income were partially offset by lower electric margin (excluding the impact of adjustments related to the adoption of new electric depreciation rates, the effects of which were offset by a reduction of revenue under regulatory direction-see Electric Operations and Other Operating Expenses) of $14 million.  All amounts are net of tax.

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• 2008 vs 2007 Net income increased primarily due to higher electric margin of $49.0 million and higher gas margin of $4.1 million.  These increases were partially offset by increased generation, transmission and distribution expenses of $1.6 million, by increased incentive compensation and other benefits of $4.5 million, by increased depreciation expense of $6.9 million, by $2.5 million due to higher customer service expense, including bad debt expense and by $1.2 million due to lower pension income.  All amounts are net of tax.

Pension Cost (Income)

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

Millions of dollars	2009			2008			2007
Income Statement Impact:
Reduction in employee benefit costs	$	(4.4	)	$	(2.4	)	$	(4.3	)
Other income		(4.0	)		(14.9	)		(14.0	)
Balance Sheet Impact:
Increase (reduction) in capital expenditures		9.1			(0.7	)		(1.3	)
Component of amount (due to) payable from Summer Station co-owner		2.7			(0.3	)		(0.4	)
Regulatory asset		31.2			-			-
Total Pension Cost (Income)	$	34.6		$	(18.3	)	$	(20.0	)

The Company recorded significant pension income in each of 2008 and 2007.  Due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets, the Company recorded significant pension cost in 2009.  However, no contribution to the pension trust was necessary in or for 2009, nor did limitations on benefit payments apply.

Additionally, in February 2009, SCE&G was granted accounting orders by the SCPSC which allow it to mitigate a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above the level of pension income which is included in current rates for its retail electric and gas distribution regulated operations.  These costs are being deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.  See further information at Liquidity and Capital Resources and Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized.  The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income.  AFC represented approximately 11.5% of income before income taxes in 2009, 6.3% in 2008 and 3.8% in 2007.

Dividends Declared

SCE&G’s Board of Directors declared the following dividends on common stock held by SCANA during 2009:

Declaration Date	Dividend Amount		Quarter Ended	Payment Date
February 19, 2009	$	42.8 million	March 31, 2009	April 1, 2009
April 23, 2009		43.0 million	June 30, 2009	July 1, 2009
July 30, 2009		45.5 million	September 30, 2009	October 1, 2009
October 28, 2009		49.6 million	December 31, 2009	January 1, 2010

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	2009		% Change			2008		% Change			2007
Operating revenues	$	2,148.9		(4.4	)%	$	2,248.1		14.6	%	$	1,961.7
Less: Fuel used in generation		822.3		(5.0	)%		865.9		30.7	%		662.3
Purchased power		16.8		(53.5	)%		36.1		10.4	%		32.7
Margin	$	1,309.8		(2.7	)%	$	1,346.1		6.3	%	$	1,266.7

• 2009 vs 2008 Margin decreased by $6.6 million due to lower residential and commercial usage (including the partially offsetting effects of favorable weather), by $11.9 million due to lower industrial sales, by lower off-system sales of $15.9 million.  Margins also decreased by $13.6 million due to the adoption of new, lower SCPSC-approved electric depreciation rates, the effect of which was offset within operating revenues.  The decreases were partially offset by higher residential and commercial customer growth of $6.2 million and by increases in base rates by the SCPSC under the BLRA of $10.8 million which became effective for bills rendered on or after March 29, 2009.

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• 2008 vs 2007 Margin increased by $74.5 million due to increased retail electric rates that went into effect in January 2008 and $16.6 million due to residential and commercial customer growth.  These increases were offset by $5.4 million due to lower off-system sales, by $3.5 million due to lower industrial sales and $10.0 million in lower residential and commercial usage.

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

Classification (in thousands)	2009		% Change			2008		% Change			2007
Residential		7,893		0.8	%		7,828		0.2	%		7,814
Commercial		7,353		(1.3	)%		7,453		(0.3	)%		7,472
Industrial		5,324		(13.5	)%		6,152		(1.8	)%		6,267
Sales for resale (excluding interchange)		1,815		(1.9	)%		1,850		(11.9	)%		2,100
Other		562		(1.2	)%		569		1.1	%		563
Total territorial		22,947		(3.8	)%		23,852		(1.5	)%		24,216
Negotiated Market Sales Tariff (NMST)		160		(63.2	)%		435		(35.3	)%		672
Total		23,107		(4.9	)%		24,287		(2.4	)%		24,888

• 2009 vs 2008 Territorial sales volumes decreased by 95 MWh due to decreased average use, partially offset by favorable weather, and by 828 MWh due to lower industrial sales volumes as a result of a recessionary economy, partially offset by an increase of 76 MWh due to residential and commercial customer growth.  NMST volumes decreased due to lower regional demand.

• 2008 vs 2007 Territorial sales volumes decreased by 252 MWh due to weather and by 115 MWh due to lower industrial sales volumes as a result of a recessionary economy, partially offset by an increase of 238 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	2009		% Change			2008		% Change			2007
Operating revenues	$	420.1		(26.0	)%	$	567.8		9.4	%	$	519.1
Less: Gas purchased for resale		276.3		(35.5	)%		428.7		10.9	%		386.7
Margin	$	143.8		3.4	%	$	139.1		5.1	%	$	132.4

• 2009 vs 2008 Margin increased by $2.7 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2008, by $3.7 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009, offset by a decrease of $3.0 million due to decreased customer usage.

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

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

Classification (in thousands)	2009		% Change		2008	% Change		2007
Residential		12,386	3.0	%	12,030	9.2	%	11,014
Commercial		12,736	(4.2	)%	13,301	8.4	%	12,270
Industrial		14,853	(10.6	)%	16,615	(8.3	)%	18,126
Transportation gas		3,323	11.6	%	2,977	5.9	%	2,811
Total		43,298	(3.6	)%	44,923	1.6	%	44,221

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• 2009 vs 2008 Residential sales volume increased primarily due to customer growth and weather.  Commercial and industrial sales volume decreased primarily as a result of weak economic conditions.

• 2008 vs 2007 Residential, commercial and transportation gas sales volume increased primarily due to customer growth.  Industrial gas sales volume decreased primarily due to a loss of customers as a result of a recessionary economy.

Other Operating Expenses

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

Millions of dollars	2009		% Change				2008		% Change			2007
Other operation and maintenance	$	489.8		(3.2	)%		$	506.2		5.9	%	$	477.9
Depreciation and amortization		255.1		(3.8		)%		265.2		(4.1	)%		276.4
Other taxes		161.9		5.0		%		154.2		5.0	%		146.9
Total	$	906.8		(2.0		)%	$	925.6		2.7	%	$	901.2

• 2009 vs 2008 Other operation and maintenance expenses decreased by $7.4 million due to lower generation, transmission and distribution expenses and by $5.0 million due to lower incentive compensation and other benefits.  Depreciation and amortization expense decreased $13.6 million due to the implementation of new, lower SCPSC-approved electric depreciation rates in 2009, offset by higher depreciation expense of $9.5 million due to 2009 net property additions.  Other taxes increased primarily due to higher property taxes.

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

Other Income (Expense)

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

Millions of dollars	2009			% Change			2008			% Change			2007
Other income	$	28.6			(20.6	)%	$	36.0			8.1	%	$	33.3
Other expenses		(11.3	)		(29.4	)%		(16.0	)		44.1	%		(11.1	)
Total	$	17.3			(13.5	)%	$	20.0			(9.9	)%	$	22.2

• 2009 vs 2008 Total other income (expense) decreased $10.9 million due to decreased pension income and by $6.9 million in gains on sale of assets in 2008.  These decreases were partially offset by an increase of $14.3 million in interest income.  (See Economic Impact Zone (EIZ) discussion under “Resolution of EIZ Tax Credit Uncertainty” below.)

• 2008 vs 2007 Other income increased by $1.9 million due to increased coal sales to non-affiliates.  Other expenses increased $1.7 million due to increased coal inventory expenses related to the increased coal sales to non-affiliates.

 Resolution of EIZ Tax Credit Uncertainty

SCE&G earned an Economic Impact Zone state income tax credit (EIZ credit) in 1996 based on qualifying property additions.  This EIZ credit exceeded its state tax liability for the 1996 tax year, leaving $15.3 million unused.  The Company’s attempt to carry forward the unused credit to tax years 1997 and 1998 was contested by the South Carolina Department of Revenue.  In September 2009, the South Carolina Supreme Court decided the matter in the Company’s favor.  As a result of the favorable resolution of this uncertainty, the Company recorded the refund for the previously contested EIZ credit of $15.3 million and an additional $14.3 million of interest income.

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Prior to this favorable Supreme Court decision, and pursuant to accounting guidance concerning income tax uncertainties, the value of the contested credit had not been reflected in the Company’s statement of income.  SCE&G’s practice has been to amortize EIZ credits to income over the lives of the properties that gave rise to the credits.  Accordingly, upon resolution of this prior uncertainty, the Company recorded a cumulative adjustment in the third quarter 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes.  The remainder of these EIZ credits will be amortized to income over the remaining life of the related properties that gave rise to the tax benefit, as a reduction in income taxes.  The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.

Interest Expense

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

Millions of dollars	2009		% Change			2008		% Change			2007
Interest on long-term debt, net	$	156.3		13.3	%	$	138.0		25.9	%	$	109.6
Other interest expense		7.4		(57.0	)%		17.2		(44.9	)%		31.2
Total	$	163.7		5.5	%	$	155.2		10.2	%	$	140.8

Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year.  Other interest expense decreased in each year primarily due to lower principal balances on short-term debt over the prior year.

Income Taxes

Income tax expense decreased in 2009 primarily due to the recognition of a tax benefit from the resolution of the EIZ tax credit uncertainty in favor of the Company (see discussion above at Other Income (Expense)) and due to changes in operating income.  Income taxes increased in 2008 primarily due to the recognition at SCE&G of $17.4 million in synthetic fuel tax credits in 2007 (see discussion under “Recognition of Synthetic Fuel Tax Credit” below) and due to changes in operating income. 

Recognition of Synthetic Fuel Tax Credits

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

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

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

Available credits were not sufficient to fully recover the construction costs of dam remediation; therefore,  recovery of remaining costs is being sought in connection with a retail electric rate application filed with the SCPSC in January 2010.  In addition, SCE&G records non-cash carrying costs on the unrecovered investment, which amounts were $5.4 million in 2009, $5.5 million in 2008 and $5.6 million in 2007.  As of December 31, 2009, remaining unrecovered costs were $75.5 million.  The Company expects these costs to be recoverable through rates.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities.  The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.  The Company’s ratio of earnings to fixed charges for the year ended December 31, 2009 was 3.25.  

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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.

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).

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $751 million in 2009 and are estimated to be $1.0 billion in 2010.

The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2010-2012, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars	2010		2011		2012
Electric Plant:
Generation (including GENCO)	$	567	$	666	$	948
Transmission		49		48		59
Distribution		142		154		184
Other		31		21		32
Nuclear Fuel		77		6		85
Gas		49		55		59
Common and Other		25		18		10
Total	$	940	$	968	$	1,377

The Company’s contractual cash obligations as of December 31, 2009 are summarized as follows:

Contractual Cash Obligations

	Payments due by period
Millions of dollars	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long-term and short-term debt including interest	$	6,709	$	452	$	959	$	365	$	4,933
Capital leases		3		1		2		-		-
Operating leases		28		7		16		1		4
Purchase obligations		7,645		744		3,706		2,002		1,193
Other commercial commitments		1,812		622		690		147		353
Total	$	16,197	$	1,826	$	5,373	$	2,515	$	6,483

Included in the table above in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s estimated projected costs for the two additional units, in future dollars and excluding AFC, are summarized below.  To the extent that actual contracts were put in place by December 31, 2009, obligations arising from these contracts are included in the purchase obligations within the Contractual Cash Obligations table above.

Future Value
Millions of dollars	Prior to 2010		2010		2011		2012		2013		After 2013		Total
Total Project Cash Outlay	$	463	$	468	$	586	$	852	$	897	$	2,700	$	5,966

Also 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.

 Included in other commercial commitments are estimated obligations for coal and nuclear fuel purchases.  See Note 11F to the consolidated financial statements.

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            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 11G to the consolidated financial statements.

In addition to the contractual cash obligations above, SCANA sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees.  The pension plan is adequately funded under current regulations, and no required contributions are anticipated until after 2011.  The Company’s cash payments under the health care and life insurance benefit plan were $9.3 million in 2009, and such annual payments are expected to increase up to $11 million in the future.

The Company does not have any recorded or unrecorded tax-related contingencies. 

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term debt and capital contributions from its parent, SCANA.  The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and the foreseeable future.

 Financing Limits and Related Matters

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

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act).  SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of short-term indebtedness.  The authority to make such issuances will expire on February 5, 2012.

At December 31, 2009, SCE&G (including Fuel Company) had available the following committed lines of credit (LOC) and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

	Millions of dollars
Lines of credit:
Committed long-term (expire December 2011)
Total	$	650
LOC advances	$	100
Weighted average interest rate		.50	%
Outstanding commercial paper (270 or fewer days) (a)	$	254
Weighted average interest rate		.33	%
Letters of credit supported by an LOC	$	.3
Available		296

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

           support. Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company

           of LOC advances or short-term commercial paper.

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

Challenging conditions during late 2008 and early 2009 tested the Company’s liquidity and its ability to access short-term funding sources.  During this period, all of the banks in the Company’s revolving credit facilities fully funded draws requested of them.  As of December 31, 2009, the Company had borrowed $100 million from its $650 million facilities, had approximately $254 million in commercial paper borrowings outstanding, was obligated under $0.3 million in LOC-supported letters of credit, and had approximately $134 million in cash and temporary investments.  The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.

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At December 31, 2009, the Company had net available liquidity of approximately $430 million, and the Company’s revolving credit facilities are in place until December 2011.  The Company’s overall debt portfolio has a weighted average maturity of over 17 years and bears an average cost of 4.34%.  Most long-term debt, other than facility draws, effectively bears fixed interest rates or is swapped to fixed.  To further preserve liquidity, the Company rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

SCE&G’s Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock.  However, SCE&G’s bond indenture contains 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, 2009, approximately $57 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its First Mortgage Bonds (Bonds) have been issued.  Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee.  Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued 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, 2009, the Bond Ratio was 5.18.

Financing Activities

During 2009 the Company experienced net cash inflows related to financing activities of $332 million primarily due to the issuance of long-term debt, partially offset by repayment of short-term debt and payment of dividends.

In December 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock representing an aggregate par value of $113.4 million.

In December 2009, SCE&G issued $150 million of First Mortgage Bonds bearing an annual interest rate of 5.50% and maturing on December 15, 2039.  Proceeds from the sale were used to finance capital expenditures, and for general corporate purposes.

In March 2009, SCE&G issued $175 million of First Mortgage Bonds bearing an annual interest rate of 6.05% and maturing on January 15, 2038.  Proceeds from the sale were used to repay short-term debt and for general corporate purposes.

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

ENVIRONMENTAL MATTERS

The Company’s regulated operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes.  Applicable statutes and rules include the Clean Air Act, as amended (CAA), the Clean Air Interstate Rule (CAIR), the Clean Water Act (CWA), 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, 2009, the Company’s capital expenditures for environmental control totaled $585.0 million.  These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $41.2 million during 2009, $43.7 million during 2008, and $34.0 million during 2007.  It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $13.1 million for 2010 and $48.4 million for the four-year period 2011-2014.  These expenditures are included in the Company’s Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.

On June 26, 2009, the United States House of Representatives narrowly passed energy legislation that would mandate significant reductions in greenhouse gas (GHG) emissions and require electric utilities to generate an increasing percentage of their power from renewable sources.  The bill would require, among other things, that GHG emissions be reduced to 17% below 2005 levels by 2020, and to 83% below 2005 levels by 2050.  Companies could meet these standards either through emission reductions or by obtaining emission allowances (Cap and Trade).  The bill also would impose a renewable energy standard (RES) on the total generation of electric utilities beginning at 6% in 2012 and increasing to 20% by 2020.  New nuclear generation would be excluded from the RES total generation baseline calculation, and one quarter of the RES mandate could be met through energy efficiency measures.  The United States Senate is also considering legislation that would address GHG emissions and would establish an

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RES.  The Company cannot predict if or when the legislation described above will become law or what requirements would be imposed on the Company by such legislation.  The Company expects that any costs incurred to comply with such legislation would be recoverable through rates.

At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2009.  The Company cannot predict whether such legislation will be introduced or enacted in 2010, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.

Air Quality

With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, SCE&G and GENCO are subject to certain climate-related financial risks, including those involving regulatory requirements responsive to GHG emissions, as well as those involving physical impacts which could arise from global climate change.  Certain other business and financial risks arising from such climate change could also arise.  The Company cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact the Company, and the following discussion should not be considered all-inclusive.

From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions.  SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants.  Further, SCE&G has announced plans to construct two new nuclear generating plants which are expected to significantly reduce GHG emission levels once they are completed and dispatched, potentially displacing some of the current coal-fired generation sources.

See also the discussion of the court action on the Clean Air Interstate Rule (CAIR) below.  Even while the rule has been in flux, the Company has continued with its scrubber and selective catalytic reactor (SCR) construction projects with the expectation that new rules will be forthcoming.  
 

In 2005, the EPA issued the CAIR which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances.  On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it.  Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements.  SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction.   SCE&G also is installing a wet limestone scrubber at Wateree Station.  The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these scrubber projects, of which approximately $435 million has already been spent.  The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

Physical effects associated with climate changes could include the impact of possible changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to the Company’s electric system, as well as impacts on employees and customers and on the Company’s supply chain and many others.   Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms.  To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties and also collects funds from customers for its storm damage reserve (see Note 1 to the consolidated financial statements).  As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams, and applicable personnel participate in ongoing training and related simulations in advance of such storms, all in order to allow the Company to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.

 In December 2009 the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA.  The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA.  The EPA has committed to issue new rules regulating such emissions by November 2011.  On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as the Company’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions.  The Company expects that any costs incurred to comply with greenhouse gas emission requirements will be recoverable through rates.

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

The EPA is conducting an enforcement initiative against the utilities industry related to the new source review provisions and the new source performance standards of the CAA.  As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the United States Department of Justice (DOJ), on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.

           To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether the Company will be affected by the initiative in the future.  The Company believes that any enforcement action relative to its compliance with the CAA would be without merit.  The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with New Source Review (NSR).

Water Quality

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

Hazardous and Solid Wastes

The EPA has publicly stated its intention to propose new federal regulations affecting the management and disposal of coal combustion products (CCP), such as ash, in 2010.  Such regulations could result in the treatment of some CCPs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.  While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

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, 2009, the federal government has not accepted any spent fuel from Summer Station or any other nuclear generating facility, and it remains unclear when the repository may become available.  SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available.

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

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Electric Operations

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List in April 2006.  AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater.  The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection.  The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2010.  The site has not been remediated nor has a clean-up cost been estimated.  Although a basis for the allocation of clean up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.  Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.

Gas Distribution

SCE&G is responsible for four decommissioned manufactured gas plant (MGP) sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control (DHEC).  SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $7.7 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates.  At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

REGULATORY MATTERS

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

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

 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.

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.

Effective February 12, 2010 the Pipeline and Hazardous Materials Safety Administration issued a final rule establishing integrity management requirements for gas distribution pipeline systems, similar to those for transmission pipelines.  The rule gives SCE&G until August 2, 2011 to develop and implement a program for compliance with the rule.  SCE&G has not determined what impact the rule will have on its operations.  SCE&G believes that any additional cost incurred to comply with the rule will be recoverable through rates.

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’s regulated operations record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities.  In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria of accounting for rate-regulated utilities, and could be required to write off its regulatory assets and liabilities.  Such an event could have a material adverse effect on the results of operations, liquidity or financial position of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded.  See Note 1B to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

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            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, 2009, the Company’s net investments in fossil/hydro and nuclear generation assets were $2.8 billion and $1.0 billion, 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, 2009 and 2008, accounts receivable included unbilled revenues of $104.3 million and $97.1 million, respectively, compared to total revenues of $2.6 billion and $2.8 billion for the years 2009 and 2008, respectively.

Nuclear Decommissioning

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

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 thereon, 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.

Accounting for Pensions and Other Postretirement Benefits

SCANA recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance.  SCANA’s plan is adequately funded under current regulations.  Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded.  Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets.  Net pension cost of $40.0 million ($34.6 million attributable to SCE&G) recorded in 2009 reflects the use of a 6.45% discount rate, derived using a cash flow matching technique, and an assumed 8.50% long-term rate of return on plan assets.  SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable.  For purposes of comparison, using a discount rate of 6.20% in 2009 would have increased SCANA’s aggregate pension income by $1.1 million.  Had the assumed long-term rate of return on assets been 8.25%, SCANA’s pension cost for 2009 would have increased by $1.5 million.

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

93

SCANA accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan.  This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense.  SCANA used a discount rate of 6.45%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $13.0 million for 2009.  Had the selected discount rate been 6.20%, the expense for 2009 would have been $0.1 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

The Company accrues for the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation in accordance with applicable accounting guidance.  The obligations are recognized at fair value in the period in which they are incurred and associated asset retirement costs are capitalized as a part of the carrying amount of the related long-lived assets.  Because such obligations relate primarily to the Company’s regulated utility operations, their recording has no significant impact on results of operations.  As of December 31, 2009, the Company has recorded an asset retirement obligation (ARO) of $111 million for nuclear plant decommissioning (as discussed above) and an ARO of $347 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines.  All of the amounts recorded in accordance with the relevant accounting guidance are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.  Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Transactions

 SCE&G does not hold significant investments in unconsolidated special purpose 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 11 to the consolidated financial statements.

94

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.  Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.

	Expected Maturity Date
December 31, 2009 Millions of dollars	2010	2011	2012	2013	2014	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	10.4	264.9	11.0	156.7	42.5	2,602.7	3,088.2	3,243.4
Average Interest Rate (%)	6.31	4.36	4.98	7.06	4.97	5.89	5.80
Variable Rate ($)						71.4	71.4	71.4
Average Variable Interest Rate (%)						3.29	3.29
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)						71.4	71.4	3.1
Average Pay Interest Rate (%)						3.29	3.29
Average Receive Interest Rate (%)						.31	.31

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

 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 $30 million at December 31, 2009 and $37 million at December 31, 2008, which amounts do not have stated interest rates associated with them.

Commodity Price Risk

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

Expected Maturity:
Options	2010	Swaps	2010
Purchased Call (Long):		Commodity Swaps:
Strike Price (a)	6.51	Pay fixed/receive variable (b)	0.1
Contract Amount (b)	15.3	Average pay rate (a)	10.3784
Fair Value (b)	0.7	Average received rate (a)	5.5720
		Fair Value (b)	0.1
(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.

95

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

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

South Carolina Electric & Gas Company

Cayce, South Carolina

We have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the "Company") as of December 31, 2009 and 2008, and the related consolidated statements of income, changes in equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009.  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 the 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 as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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, present fairly in all material respects the information set forth therein.

/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 1, 2010

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2009			2008
Assets
Utility Plant In Service:	$	9,286		$	8,918
Accumulated Depreciation and Amortization		(2,926	)		(2,794	)
Construction Work in Progress		1,138			704
Nuclear Fuel, Net of Accumulated Amortization		97			77
Utility Plant, Net		7,595			6,905
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		42			46
Assets held in trust, net-nuclear decommissioning		69			54
Nonutility Property and Investments, Net		111			100
Current Assets:
Cash and cash equivalents		134			119
Receivables, net of allowance for uncollectible accounts of $3 and $3		397			483
Receivables-affiliated companies		41			23
Inventories (at average cost):
Fuel		259			172
Materials and supplies		107			100
Emission allowances		10			15
Prepayments and other		89			155
Total Current Assets		1,037			1,067
Deferred Debits and Other Assets:
Regulatory assets		936			854
Other		134			126
Total Deferred Debits and Other Assets		1,070			980
Total	$	9,813		$	9,052

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December 31, (Millions of dollars)	2009		2008
Capitalization and Liabilities
Common equity	$	3,162	$	2,704
Noncontrolling interest		97		95
Total Equity		3,259		2,799
Preferred Stock		-		113
Long-Term Debt, net		3,158		3,033
Total Capitalization		6,417		5,945
Current Liabilities:
Short-term borrowings		254		34
Current portion of long-term debt		18		140
Accounts payable		250		187
Affiliated payables		144		80
Customer deposits and customer prepayments		51		56
Taxes accrued		128		120
Interest accrued		51		50
Dividends declared		50		44
Derivative liabilities		-		55
Other		43		28
Total Current Liabilities		989		794
Deferred Credits and Other Liabilities:
Deferred income taxes, net		972		890
Deferred investment tax credits		111		102
Asset retirement obligations		458		437
Due to parent – pension and other postretirement benefits		195		236
Regulatory liabilities		639		608
Other		32		40
Total Deferred Credits and Other Liabilities		2,407		2,313
Commitments and Contingencies (Note 11)		-		-
Total	$	9,813	$	9,052

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, (Millions of dollars)	2009			2008			2007
Operating Revenues:
Electric	$	2,149		$	2,248		$	1,962
Gas		420			568			519
Total Operating Revenues		2,569			2,816			2,481
Operating Expenses:
Fuel used in electric generation		822			866			662
Purchased power		17			36			33
Gas purchased for resale		276			429			387
Other operation and maintenance		490			506			478
Depreciation and amortization		255			265			276
Other taxes		162			155			147
Total Operating Expenses		2,022			2,257			1,983
Operating Income		547			559			498
Other Income (Expense):
Other income		28			36			33
Other expenses		(11	)		(16	)		(11	)
Interest charges, net of allowance for borrowed funds used during construction of $22, $15 and $13		(164	)		(155	)		(141	)
Allowance for equity funds used during construction		28			13			2
Total Other Expense		(119	)		(122	)		(117	)
Income Before Income Tax Expense, Earnings (Losses) from Equity Method Investments
and Preferred Stock Dividends		428			437			381
Income Tax Expense		140			158			109
Income Before Earnings (Losses) from Equity Method Investments		288			279			272
Earnings (Losses) from Equity Method Investments		-			3			(20	)
Net Income		288			282			252
Less Net Income Attributable to Noncontrolling Interest		7			9			7
Net Income Attributable to SCE&G		281			273			245
Less Preferred Stock Dividends		(9	)		(7	)		(7	)
Earnings Available for Common Shareholder	$	272		$	266		$	238
Dividends Declared on Common Stock	$	179		$	165		$	150

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2009			2008			2007
Cash Flows From Operating Activities:
Net income	$	288		$	282		$	252
Adjustments to reconcile net income to net cash provided from operating activities:
Losses (earnings) from equity method investments		-			(3	)		20
Depreciation and amortization		266			265			276
Amortization of nuclear fuel		18			17			19
Allowance for equity funds used during construction		(28	)		(13	)		(2	)
Carrying cost recovery		(5	)		(5	)		(6	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables		91			(9	)		(51	)
Inventories		(144	)		(76	)		(43	)
Prepayments		43			(23	)		(32	)
Regulatory assets		(84	)		(25	)		17
Deferred income taxes, net		74			99			27
Other regulatory liabilities		(2	)		(7	)		53
Accounts payable		(1	)		13			38
Taxes accrued		8			4			4
Interest accrued		1			17			-
Changes in other assets		(35	)		4			41
Changes in other liabilities		(54	)		(110	)		(73	)
Net Cash Provided From Operating Activities		436			430			540
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(745	)		(739	)		(613	)
Nonutility property additions		(6	)		(8	)		(6	)
Proceeds from investments and sales of assets		27			8			5
Investment in affiliate		(23	)		(18	)		-
Investments		(6	)		(2	)		19
Net Cash Used For Investing Activities		(753	)		(759	)		(595	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		421			1,109			-
Contribution from parent		348			15			76
Repayment of debt		(423	)		(13	)		(6	)
Redemption of preferred stock		(113	)		-			(1	)
Dividends		(182	)		(164	)		(143	)
Short-term borrowings - affiliate, net		61			(110	)		44
Short-term borrowings, net		220			(430	)		102
Net Cash Provided From (Used For) Financing Activities		332			407			72
Net Increase (Decrease) in Cash and Cash Equivalents		15			78			17
Cash and Cash Equivalents, January 1		119			41			24
Cash and Cash Equivalents, December 31	$	134		$	119		$	41
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $22, $15 and $13)	$	152		$	119		$	104
- Income taxes		61			51			70
Noncash Investing and Financing Activities:
Accrued construction expenditures		141			74			58

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE INCOME

								Accumulated
								Other
	Common Stock				Retained			Comprehensive				Noncontrolling		Total
Millions	Shares		Amount		Earnings			Income (Loss)				Interest		Equity
Balance at December 31, 2006		40	$	1349	$	1,115		$	(7	)	$	86		$	2,543
Comprehensive Income (Loss):
Earnings Available for Common Shareholder						238						7			245
Deferred Cost of Employee Benefit Plans,
net of taxes $(1)									(1	)					(1	)
Total Comprehensive Income (Loss)						238			(1	)		7			244
Capital Contributions From Parent				76											76
Cash Dividends Declared						(148	)					(4	)		(152	)
Balance at December 31, 2007		40		1425		1,205			(8	)		89			2,711
Comprehensive Income (Loss):
Earnings Available for Common Shareholder						266						9			275
Deferred Cost of Employee Benefit Plans,
net of taxes $(24)									(38	)					(38	)
Total Comprehensive Income (Loss)						266			(38	)		9			237
Capital Contributions From Parent				15											15
Cash Dividends Declared						(161	)					(3	)		(164	)
Balance at December 31, 2008		40	$	1440	$	1,310		$	(46	)		95		$	2,799
Comprehensive Income (Loss):
Earnings Available for Common Shareholder						272						7			279
Deferred Cost of Employee Benefit Plans,
net of tax $8									13						13
Total Comprehensive Income (Loss)						272			13			7			292
Capital Contributions From Parent				348											348
Cash Dividends Declared						(175	)					(5	)		(180	)
Balance at December 31, 2009		40	$	1,788	$	1,407		$	(33	)		97		$	3,259

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Organization and Principles of Consolidation

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

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

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 noncontrolling interest in the Company’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 570 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.  The effects of these transactions are eliminated in consolidation.  Substantially all of GENCO’s property (carrying value of approximately $497 million) serves as collateral for its long-term borrowings.  Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances.  See also Note 5.

B.      Basis of Accounting

The Company has significant cost-based, rate-regulated operations and recognizes in its 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 regulatory assets and regulatory liabilities, summarized as follows.

	December 31,
Millions of dollars	2009		2008
Regulatory Assets:
Accumulated deferred income taxes	$	167	$	166
Under-collections–electric fuel adjustment clause		55		-
Environmental remediation costs		19		19
Asset retirement obligations and related funding		265		250
Franchise agreements		50		50
Deferred employee benefit plan costs		306		325
Planned major maintenance		5		-
Other		69		44
Total Regulatory Assets	$	936	$	854

Regulatory Liabilities:
Accumulated deferred income taxes	$	29	$	30
Other asset removal costs		535		503
Storm damage reserve		44		48
Planned major maintenance		-		11
Other		31		16
Total Regulatory Liabilities	$	639	$	608

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.

103

Under-collections–electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings which are expected to be recovered in retail electric rates during the period January 2011 through April 2012.  As a part of a settlement agreement approved by the SCPSC in April 2009, SCE&G is allowed to collect interest on the deferred balance during the recovery period.

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.

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 employee benefit plan costs represent amountsof pension and other postretirement benefit costs which were accrued as liabilities, and the costs deferred pursuant to specific regulatory orders (see Note 3), but which are expected to be recovered through utility rates.  

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates.  SCE&G applied costs of $10.0 million in 2009 and $7.3 million in 2008 to the reserve.  See Note 2.

Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved through specific SCPSC orders.  SCE&G is collecting $8.5 million annually, ending December 2013, 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 SCPSC or the United States Federal Energy Regulatory Commission (FERC) have reviewed and approved through specific orders most of the items shown as regulatory assets.  Other regulatory assets include certain costs which have not been approved for recovery by the SCPSC or by FERC.  In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company.  In addition, the Company hasdeferred in utility plant in service approximately $75.5 million of unrecovered costs related to the Lake Murray backup dam project and $70.1 million of costs related to the installation of selective catalytic reactor (SCR) technology at its Cope Station generating facility.  See Note 11B.  These costs are not currently being recovered, but are expected to be recovered through rates in future periods.  In the future, as a result of deregulation or other changes in the regulatory environment, or changes in accounting requirements the Company 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.

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SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) jointly own Summer Station in the proportions of two-thirds and one-third, respectively.  The parties share the operating costs and energy output of the plant in these proportions.  Each party, however, provides its own financing.  Plant-in-service related to SCE&G’s portion of Summer Station was approximately $1.0 billion as of December 31, 2009 and 2008 (including amounts capitalized related to the recording of AROs).  Accumulated depreciation associated with SCE&G’s share of Summer Station was $538.3 million and $527.6 million as of December 31, 2009 and 2008, respectively (including amounts capitalized related to the recording of AROs).  SCE&G’s share of the direct expenses associated with operating Summer Station is included in other operation and maintenance expenses and totaled $92.7 million in 2009, $87.4 million in 2008 and $86.7 million in 2007.

In addition, SCE&G and Santee Cooper are constructing two new nuclear units at the site of Summer Station that will be jointly owned in the proportions of 55 percent and 45 percent, respectively, with each party providing its own financing.  SCE&G will be the operator of the new units.  SCE&G’s portion of the construction work in progress for the new units was $476.5 million at December 31, 2009 and $126.7 million at December 31, 2008.

Planned major maintenance costs related to certain fossil and hydro turbine equipment and nuclear refueling outages are accrued in periods other than when 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.  Through 2013, SCE&G is authorized to collect $8.5 million annually through electric rates to offset turbine maintenance expenditures.  For the year ended December 31, 2009, SCE&G incurred $17.1 million for turbine maintenance.  Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset 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 $1.1 million per month from January 2007 through June 2008 for its portion of the outage in the spring of 2008 and accrued $1.2 million per month from July 2008 through December 2009 for its portion of the outage in the fall of 2009.  Total costs for the 2008 outage were $25.7 million, of which SCE&G was responsible for $17.1 million.  Total costs for the 2009 outage were $32.7 million, of which SCE&G was responsible for $21.8 million.  As of December 31, 2008, SCE&G had an accrued balance of $7.3 million.  There was no accrued balance as of December 31, 2009.

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 calculated AFC using average composite rates of 7.4% for 2009, 6.0% for 2008 and 5.8% for 2007.  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 $104.3 million at  December 31, 2009 and $97.1 million at December 31, 2008.

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

Customers subject to the purchased gas adjustment (PGA) are billed based on a fixed cost of gas determined by the SCPSC during annual gas cost recovery hearings.  Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual hearing.  In addition, included in these amounts are realized gains and losses incurred in the Company’s natural gas hedging program.

The Company’s gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment (WNA) 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 2.95% in 2009, 3.15% in 2008 and 3.13% in 2007.

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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 United States 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 2009, 2008 and 2007) 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 thereon, 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 $8.7 million in 2009 and $1.8 million in 2008.

Taxes that are billed to and collected from customers are recorded 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 within 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 are amortized over the term of the replacement debt, also as interest charges.

J.       Environmental

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

K.      Cash and Cash Equivalents

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

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L.      Commodity Derivatives

SCE&G hedges gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options.  SCE&G’s tariffs include a PGA 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

Effective for the year beginning January 1, 2010, the Company will adopt accounting guidance that requires an enterprise to perform an analysis to determine whether it has a controlling financial interest in a variable interest entity.   The adoption of this guidance is not expected to significantly impact the Company’s results of operations, cash flows or financial position.

Effective June 30, 2009, the Company adopted new accounting guidance thatmakes the Company’s management responsible for subsequent-events accounting and disclosure.  The adoption of this guidancedid not impact the Company’s results of operations, cash flows or financial position.  

 Effective January 1, 2009, the Company adopted accounting guidance that requires enhanced disclosures about an entity’s derivative and hedging activities to include how derivative instruments are accounted for and the effect of such activities on the entity’s financial statements.  The adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.  

Effective January 1, 2009, the Company adopted accounting guidance thatrequires the acquiring entity in a business combination to recognize the assets acquired and the liabilities assumed at their fair values at the acquisition date and to disclose all of the information needed to evaluate and understand the nature and financial effect of the business combination.  The adoption of this guidancedid not impact the Company’s results of operations, cash flows or financial position.

 Effective January 1, 2009, the Company adopted accounting guidance that requires entities to report noncontrolling (minority) interests in subsidiaries as equity. The adoption of this guidance did not significantly impact the Company’s results of operations or cash flows but did result in a net $11 million reduction in total equity.

 Additionally, the adoption of guidance on noncontrolling interestshad the effect of reclassifying earnings attributable to non-controlling interest in the consolidated statement of operations from other income and expense to separate line items.  This guidance also required that net income be adjusted to include the net income attributable to the non-controlling interest, and a new separate caption for net income attributable to common shareholders be presented in the consolidated statement of operations.  Thus, after adoption of this guidance, net income increased by $9 million and $7 million for the years 2008 and 2007, respectively, and net income attributable to SCE&G is equal to net income as previously reported prior to the adoption of this guidance.

SCE&G has corrected the presentation of the preferred stock not subject to purchase or sinking funds to present these preferred securities in a manner consistent with temporary equity.  Although the effects are not material to previously issued balance sheets, the presentation of these amounts has been corrected as of December 31, 2008 by presenting these $106 million of preferred securities separately from common equity and eliminating the “Shareholder’s Investment” section and related total.  This change had no impact on income or on cash flows for any period presented.

N.      Affiliated Transactions

Carolina Gas Transmission Corporation (CGT) transports natural gas to the Company to supply certain electric generation requirements and to serve SCE&G’s retail gas customers.  SCE&G had approximately $2.8 million payable to CGT for transportation services at December 31, 2009 and approximately $0.7 million in receivables, related to certain transportation refunds, at December 31, 2008. 

 The Company purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating Station, Urquhart Electric Generation Station and to serve its retail gas customers.  Such purchases totaled approximately $160.8 million in 2009, $290.5 million in 2008 and $208.9 million in 2007.  SCE&G’s payables to SEMI for such purposes were $13.3 million and $11.1 million as of December 31, 2009 and 2008, respectively.

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The Company held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel. The partnerships ceased operations as a result of the expiration of the synthetic fuel tax credits program at the end of 2007, and they were dissolved in 2008.  The Company purchased synthetic fuel from these affiliated companies of $281.6 million in 2007. The Company made cash investments in these affiliated companies of $2.2 million in 2008 and $16.2 million in 2007.  

SCE&G purchases shaft horsepower from a cogeneration facility.  The facility is owned by a limited liability company (LLC) in which, prior to July 1, 2008, SCANA held an equity method investment.  Transactions subsequent to June 30, 2008 were not considered to be affiliated transactions.   SCE&G made affiliated purchases of shaft horsepower from the LLC of $14.7 million in 2008 and $27.7 million in 2007.

The Company participates in a utility money pool.  Money pool borrowings and investments bear interest at short-term market rates.  The Company incurred interest expense on money pool borrowings of $0.2 million in 2009 and of $4.2 million in 2008 and 2007.  At December 31 2009 and December 31, 2008, the Company owed an affiliate $29.2 million and had a net receivable of $9.1 million, respectively.

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.

2.       RATE AND OTHER REGULATORY MATTERS

Electric

SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.  In April 2009, the SCPSC approved a settlement agreement between SCE&G, the South Carolina Office of Regulatory Staff (ORS), and others authorizing SCE&G to increase the fuel cost portion of its electric rates, effective with the first billing cycle of May 2009.  As a part of the settlement, SCE&G agreed to spread the recovery of undercollected fuel costs over a three-year period ending April 2012, as further described in Note 1B.  SCE&G is allowed to collect interest on the deferred balance.

In January 2010, SCE&G filed an application with the SCPSC requesting a 9.52% overall increase to retail electric base rates.  If approved, the increase in rates would be phased in over three periods in July 2010, January 2011 and July 2011.  A public hearing on this matter is scheduled to begin on May 24, 2010.

In December 2009, SCE&G submitted to the FERC for filing revised tariff sheets to change the network and point to point transmission rates under SCE&G’s Open Access Transmission Tariff.  The request, if approved, would result in an annual revenue increase of $5.6 million.   The requested rates utilize a cost of service formula, which departs from the traditional rate structure currently in effect.

In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the Base Load Review Act (the BLRA) to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station.  The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.  The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.  

In June 2009, SCE&G filed a request with the SCPSC for approval of the implementation of certain demand reduction and energy efficiency programs (DSM programs).  SCE&G has requested the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM programs, along with an incentive for investing in such programs.  The SCPSC has scheduled a hearing on SCE&G’s request for April 1, 2010.

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 In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

 In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011 or early 2012. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.

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

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.  In more recent actions, the SCPSC also approved SCE&G’s request to apply against the reserve certain tree trimming expenditures in excess of amounts included in base rates through 2010.

Gas

The Natural Gas Rate Stabilization Act (RSA) 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 infrastructure.  In October 2009, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $13 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle of November 2009.

In October 2008, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $3.7 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle of November 2008.

In October 2007, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $4.6 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle in November 2007.

SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities.  SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average.  In December 2009, in connection with the annual review of the PGA and the gas purchasing policies of SCE&G, the SCPSC determined that SCE&G’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 17 months ended July 31, 2009.  

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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, 2009 the Company’s net periodic benefit cost for the pension plan was $34.6 million.  For the years ended December 31, 2008 and 2007, the Company’s net periodic benefit income for the pension plan was $18.3 million and $20.0 million, respectively.  Net periodic benefit cost was $13.0 million, $13.0 million and $12.8 million for 2009, 2008 and 2007, respectively, for the postretirement plan.

Additionally, in February 2009, SCE&G was granted accounting orders by the SCPSC under which it is mitigating a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above that which is included in current rates for its retail electric and gas distribution regulated operations.  These costs are being deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.  

Stock Purchase Savings Plan

The Company participates in the SCANA Stock Purchase Savings Plan into which eligible employees may contribute.  Eligible employees may defer up to 25% of eligible earnings subject to certain limits and may diversify their investments.  Employee deferrals are fully vested and nonforfeitable at all times.  The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings.  Total matching contributions made to the plan for 2009, 2008 and 2007 were $16.6 million, $16.1 million and $14.9 million, respectively.  These matching contributions were made in the form of SCANA common stock.

Share-Based Compensation

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

            Compensation costs related to share-based payment transactions are required to be recognized in the financial statements. With limited exceptions, including those liability awards discussed below, 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.

Liability Awards

The 2007-2009 performance cycle provides for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle.  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 the performance shares.  Payout of performance share awards was 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%).  Accordingly, payouts under the 2007 three-year cycle were earned for each year that performance goals were met during the three-year cycle, though payments were deferred until the end of the cycle and were contingent upon the participants still being employed by SCANA at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability.   Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2010.

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

In the 2009-2011 performance cycle, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash.  The remaining 80% of the awards were made in performance shares with payment criteria identical to those awarded for the 2008-2010 performance cycle.

Compensation cost of all these liability awards is recognized over their respective three-year performance periods 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 related to similar prior programs totaling $1.7 million in 2009 and $0.4 million in 2008

were paid.  No such payments were made in 2007.

 Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $4.5 million in 2009, $10.7 million in 2008 and $3.8 million in 2007.  Fair value adjustments resulted in capitalized compensation costs of $0.9 million in 2009, $1.8 million in 2008 and $0.7 million in 2007.

Equity Awards

A summary of activity related to nonvested shares follows:

		Weighted Average
		Grant-Date
Nonvested Shares	Shares	Fair Value
Nonvested at January 1, 2008	-	$	-
Granted	75,824		37.33
Forfeited	1,236		37.35
Nonvested at December 31, 2008	74,588		37.33
Forfeited	2,399		37.33
Nonvested at December 31, 2009	72,189		37.33

Nonvested shares were granted at a price corresponding to the opening price of SCANA common stock on the date of the grant.  The Company expensed compensation costs for nonvested shares of $0.1 million in 2009 and 2008.  Tax benefits and capitalized compensation costs in 2009 and 2008 were not significant.  No shares were granted under the plan in 2009, and none were vested in any year presented.

A summary of activity related to nonqualified stock options follows:

Stock Options	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2006		385,940		$	27.56
Exercised		(258,756	)		27.62
Outstanding-December 31, 2007		127,184			27.45
Exercised		(20,720	)		27.49
Outstanding-December 31, 2008		106,464			27.44
Exercised		(2,875	)		27.50
Outstanding-December 31, 2009		103,589			27.44

No stock options have been granted since August 2002, and all options were fully vested in August 2005.  No options were forfeited during any period presented.  The options expire ten years after the grant date.  At December 31, 2009, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 1.9 years.

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The exercise of stock options during 2009 was satisfied using original issue shares, and during 2007 and 2008 such exercise was satisfied using a combination of original issue shares and open market purchases of SCANA’s common stock.  For the years ended December 31, 2009 and 2008, cash realized upon the exercise of options and related tax benefits were not significant.  For the year ended December 31, 2007, cash realized upon the exercise of options totaled $7.1 million, and related tax benefits credited to SCANA’s additional paid in capital (common equity) during the period totaled $1.5 million.

4.       LONG-TERM DEBT

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

			2009					2008
Dollars in millions	Maturity		Balance		Rate			Balance		Rate
First Mortgage Bonds (secured)	2011-2039	$	2,560		6.03	%	$	2,335		6.07	%
GENCO Notes (secured)	2011-2024		272		5.93	%		276		5.95	%
Industrial and Pollution Control Bonds (a)	2012-2038		228		4.63	%		228		4.63	%
Borrowings Under Credit Agreements	2011		100		.50	%		285		1.61	%
Other	2010-2027		30					62
Total debt			3,190					3,186
Current maturities of long-term debt			(18	)				(140	)
Unamortized discount			(14	)				(13	)
Total long-term debt, net		$	3,158				$	3,033

(a)  Includes $71.4 million of variable rate debt hedged by fixed rate swaps.

The annual amounts of long-term debt maturities for the years 2010 through 2014 are summarized as follows:

Year	Millions of dollars
2010	$	18
2011		272
2012		17
2013		163
2014		46

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

At December 31, 2009 and 2008, SCE&G (including Fuel Company) had available the following committed lines of credit (LOC) and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

Millions of dollars	2009			2008
Lines of credit:
Committed long-term (expire December 2011)
Total	$	650		$	650
LOC advances	$	100			285
Weighted average interest rate		.50	%		1.61	%
Outstanding commercial paper (270 or fewer days) (a)	$	254		$	34
Weighted average interest rate		.33	%		5.69	%
Letters of credit supported by an LOC	$	.3			-
Available		296			331

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

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

     commercial paper or LOC advances.

SCE&G and Fuel Company have commercial paper programs in the amount of $350 million and $250 million, respectively.  SCE&G has guaranteed the short-term borrowings of Fuel Company.

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

The South Carolina Jobs-Economic Development Authority (JEDA) issued $35.0 million of Industrial Revenue Bonds in December 2008, the proceeds of which were loaned to SCE&G.  The payment of the principal and interest on the bonds is secured by a letter of credit issued by Branch Banking and Trust Company.  The bonds mature on December 1, 2038.  This letter of credit expires on December 10, 2011.  Similarly, JEDA issued $36.4 million of Industrial Revenue Bonds in November 2008, the proceeds of which were loaned to GENCO and guaranteed by SCANA.  The bonds mature on December 1, 2038.  The payment of the principal and interest on these bonds is secured by a letter of credit issued by Branch Banking and Trust Company.  This letter of credit expires on November 9, 2011.

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

6.       RETAINED EARNINGS

SCE&G’s bond indenture contains 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, 2009, $57 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

7.       PREFERRED STOCK

On December 30, 2009, SCE&G redeemed all outstanding shares of its preferred stock.  The fair value of the preferred shares redeemed exceeded their carrying value by approximately $2.1 million.  This excess payment is reflected on the statement of income as a return to preferred shareholders within preferred stock dividends.

8.       INCOME TAXES

Total income tax expense attributable to income for 2009, 2008 and 2007 is as follows:

Millions of dollars	2009			2008			2007
Current taxes:
Federal	$	60		$	32		$	63
State		(9	)		3			9
Total current taxes		51			35			72
Deferred taxes, net:
Federal		75			111			34
State		6			13			4
Total deferred taxes		81			124			38
Investment tax credits:
Deferred-state		20			5			5
Amortization of amounts deferred-state		(9	)		(3	)		(3	)
Amortization of amounts deferred-federal		(3	)		(3	)		(3	)
Total investment tax credits		8			(1	)		(1	)
Total income tax expense	$	140		$	158		$	109

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The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows:

Millions of dollars	2009			2008			2007
Net income	$	281		$	273		$	245
Income tax expense		140			158			109
Noncontrolling interest		7			9			7
Total pre-tax income	$	428		$	440		$	361
Income taxes on above at statutory federal income tax rate	$	150		$	154		$	126
Increases (decreases) attributed to:
Allowance for equity funds used during construction		(10	)		(5	)		(1	)
State income taxes (less federal income tax effect)		5			12			10
Synthetic fuel tax credits		-			-			(17	)
Amortization of federal investment tax credits		(3	)		(3	)		(3	)
Domestic production activities deduction		(4	)		(1	)		(4	)
Other differences, net		2			1			(2	)
Total income tax expense	$	140		$	158		$	109

The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $979 million at December 31, 2009 and $890 million at December 31, 2008 are as follows:

Millions of dollars	2009		2008
Deferred tax assets:
Nondeductible reserves	$	82	$	83
Nuclear decommissioning		42		40
Unamortized investment tax credits		53		51
Deferred compensation		9		10
Unbilled revenue		15		13
Pension plan income		-		18
Other		1		13
Total deferred tax assets		202		228
Deferred tax liabilities:
Property, plant and equipment		977		901
Pension plan income		12		-
Deferred employee benefit plan costs		106		125
Deferred fuel costs		42		51
Other		44		41
Total deferred tax liabilities		1,181		1,118
Net deferred tax liability	$	979	$	890

The Company is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns.  The Internal Revenue Service (IRS) has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2005 are closed for additional assessment.  With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2006.  

In September 2009, an income tax uncertainty was resolved in the Company’s favor upon the receipt of a favorable ruling in litigation of a state tax issue, which resulted in a refund of $15.3 million in state income taxes, plus interest.  While the total of this tax benefit that will impact the effective tax rate will be $15.3 million, such impact is not expected to be material in the future years because, under regulatory accounting provisions, the tax benefit recorded is being amortized into earnings over the remaining life of property additions that gave rise to the tax benefit.   No other material changes in the status of the Company’s uncertain tax positions have occurred during any period presented. 

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2009, 2008 and 2007.

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9.       DERIVATIVE FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  The Company recognizes changes in the fair value of derivative instruments either in earnings or 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, for interest rate swaps, discounted cash flow models with independently sourced data.

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 for SCANA and each of its subsidiaries, including SCE&G.  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.

Commodity Derivatives

SCE&G 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.  Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  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.

        SCE&G hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options.  SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred.  The SCPSC has ruled that the results of these hedging activities are to be included in the PGA.  As such, the cost of derivatives and gains and losses on such 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.  These derivative financial instruments are not formally designated as hedges under applicable accounting guidance.

Interest Rate Swaps

The Company uses interest rate swaps to manage interest rate risk on certain debt issuances.  The Company uses swaps to synthetically convert variable rate debt to fixed rate debt.  In addition, in anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements which are designated as cash flow hedges.  The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities.  Ineffective portions of changes in fair value are recognized in income.

The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

At December 31, 2009, SCE&G was party to natural gas derivative contracts for 2,365,000 dekatherms.  Also at December 31, 2009, the Company was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $71.4 million.

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At December 31, 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheet as follows:

	Fair Values of Derivative Instruments
		Asset Derivatives			Liability Derivatives
		Balance Sheet		Fair	Balance Sheet		Fair
Millions of dollars		Location (a)		Value	Location (a)		Value
Derivatives designated as hedging instruments
Interest rate contracts		Other deferred debits	$	4	Other deferred credits	$	1
Total			$	4		$	1

Derivatives not designated as
hedging instruments
Commodity contracts	Prepayments and other	$	1
Total		$	1

(a)  Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses.  In the    

     Company’s consolidated balance sheet, unrealized gain and loss positions with the same counterparty are reported as

     either a net asset or liability.

The effect of derivative instruments on the statement of income is as follows:

			Gain or (Loss) Deferred	Gain or (Loss) Reclassified from
Derivatives in Cash Flow			in Regulatory Accounts	Deferred Accounts into Income
Hedging Relationships			(Effective Portion)	(Effective Portion)
Millions of dollars			2009	Location		Amount
Interest rate contracts	$	42		Interest expense	$		(3	)
Total	$	42			$		(3	)

Derivatives Not Designated as
Hedging Instruments	Gain or (Loss) Recognized in Income
Millions of dollars	Location		Amount
Commodity contracts	Gas purchased for resale	$	(16)
Total		$	(16)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing interest rate hedge ineffectiveness totaled $1.2 million, net of tax, in 2009.  These amounts are recorded within interest expense on the statement of income.

Credit Risk Considerations

Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of December 31, 2009, the Company has posted no collateral related to derivatives with contingent provisions that are in a net liability position.  If all of the contingent features underlying these instruments were fully triggered as of December 31, 2009, the Company would be required to post an additional $43,258 of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2009, is $43,258.

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10.     FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.  The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows: 

		Fair Value Measurements Using
		Quoted Prices in Active		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of December 31, 2009
Assets - Derivative instruments	$	1	$	4
Liabilities - Derivative instruments		-		1
As of December 31, 2008
Assets - Derivative instruments	$	6	$	14
Liabilities - Derivative instruments		2		60

There were no fair value measurements based on significant unobservable inputs (Level 3) for either date presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2009 and December 31, 2008 were as follows:

	December 31, 2009				December 31, 2008
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,175.1	$	3,330.4	$	3,173.2	$	3,297.1
Preferred stock		-		-		113.8		96.8

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 as of December 31, 2008 was estimated using market quotes.  At December 31, 2009, all shares of preferred stock had been redeemed.  See additional disclosure at Note 7.

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

11.     COMMITMENTS AND CONTINGENCIES

A.      Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.6 billion.  Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year.  SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be $78.3 million per incident, but not more than $11.7 million per year. 

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited.  The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses.  Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.2 million.

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

B.      Environmental

In December 2009 the United States Environmental Protection Agency (EPA) issued a final finding that atmospheric concentrations of greenhouse gasses (GHG) endanger public health and welfare within the meaning of Section 202(a) of the Clean Air Act, as amended (CAA).  The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA.  The EPA has committed to issue new rules regulating such emissions by November 2011.  On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as SCE&G’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions.  The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In  2005, the EPA issued the Clean Air Interstate Rule (CAIR), which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances.  On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it.  Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements.  SCE&G has completed installation of a selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction  and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction.   SCE&G also is installing a wet limestone scrubber at Wateree Station.  The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these scrubber projects.   The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

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

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List in April 2006.  AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater.  The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection.  The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that is expected to be completed in 2010.  The site has not been remediated nor has a clean-up cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.  Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, if any, 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).

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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 $7.7 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates.  At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.

C.      Claims and Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette, and Mark Rudd and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. (SCI) was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit.  The plaintiff alleges that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications.  The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims.  SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way.  In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to easement grantors situated in Charleston County, South Carolina.  In February 2008, the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County.  In July 2008, the plaintiff’s motion to add SCI to the lawsuit as an additional defendant was granted.  Trial is not anticipated before the summer of 2010.   SCE&G and SCI 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.

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

D.      Nuclear Generation

In 2008, SCE&G and Santee Cooper entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five year escalation rates as required by the SCPSC.

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 2031.  Rent expense totaled approximately $16.5 million in 2009, $12.7 million in 2008 and $15.8 million in 2007.  Future minimum rental payments under such leases are as follows:

	Millions of dollars
2010	$	7
2011		7
2012		5
2013		4
2014		1
Thereafter		4
Total	$	28

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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 $756.9 million in 2009, $949.8 million in 2008 and $728.3 million in 2007.  Future payments under such purchase commitments are as follows:

	Millions of dollars
2010	$	718
2011		914
2012		1,366
2013		1,402
2014		1,088
Thereafter		2,112
Total	$	7,600

G.      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.

The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations.  As of December 31, 2009, the Company has recorded an ARO of approximately $111 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $347 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	2009			2008
Beginning balance	$	437		$	294
Liabilities incurred		-			-
Liabilities settled		(1	)		(1	)
Accretion expense		23			16
Revisions in estimated cash flows		(1	)		128
Ending Balance	$	458		$	437

Revisions in estimated cash flows in 2008 related to the expectation of higher costs associated with coal ash disposal than had been assumed in the 2007 cash flow analysis.

12.     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.

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Disclosure of Reportable Segments (Millions of dollars)

2009		Electric Operations		Gas Distribution		Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	2,149	$	420		-		$	2,569
Intersegment Revenue		-		2	$	(2	)		-
Operating Income (Loss)		505		43		(1	)		547
Interest Expense		15		-		149			164
Depreciation and Amortization		244		21		(10	)		255
Segment Assets		7,312		558		1,943			9,813
Expenditures for Assets		817		39		(105	)		751
Deferred Tax Assets		n/a		n/a		n/a			n/a

2008
Customer Revenue	$	2,248	$	568		-		$	2,816
Intersegment Revenue		-		4	$	(4	)		-
Operating Income (Loss)		523		40		(4	)		559
Interest Expense		15		-		140			155
Depreciation and Amortization		254		20		(9	)		265
Segment Assets		6,602		529		1,921			9,052
Expenditures for Assets		859		64		(176	)		747
Deferred Tax Assets		n/a		n/a		n/a			n/a

2007
Customer Revenue	$	1,962	$	519		-		$	2,481
Intersegment Revenue		-		6	$	(6	)		-
Operating Income (Loss)		464		41		(7	)		498
Interest Expense		16		-		125			141
Depreciation and Amortization		257		19		-			276
Segment Assets		5,925		480		1,572			7,977
Expenditures for Assets		540		51		28			619
Deferred Tax Assets		n/a		n/a		5			5

Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments.  As a result, the Company does not allocate interest charges, income tax expense or assets other than utility plant to its segments.  Interest income is not reported by segment and is not material.  The Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

The consolidated financial statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income.  Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments.  Segment Assets include utility plant, net for all reportable segments.  As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments.  Adjustments to Interest Expense and Deferred Tax Assets include the totals from the Company that are not allocated to the segments.  Expenditures for Assets are adjusted for revisions to estimated cash flows related to asset retirement obligations, and totals not allocated to other segments.

13.     QUARTERLY FINANCIAL DATA (UNAUDITED)

2009 Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	657	$	596	$	681	$	635	$	2,569
Operating income		128		119		178		122		547
Net income attributable to SCE&G		62		59		107		53		281

2008 Millions of dollars
Total operating revenues	$	693	$	698	$	776	$	649	$	2,816
Operating income		125		127		190		117		559
Net income attributable to SCE&G		59		60		100		54		273

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PART II,

ITEMS 9, 9A, 9A(T) AND 9B

PART III

 AND

PART IV

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SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

                  FINANCIAL DISCLOSURE

   Not Applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2009, an evaluation was performed under the supervision and with the participation of SCANA Corporation’s (SCANA) management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures.  For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure.  Based on that evaluation, SCANA’s management, including the CEO and CFO, concluded that SCANA’s disclosure controls and procedures were effective as of December 31, 2009.  There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2009 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, 2009, 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, 2009.  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, 2009, 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.

123

ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

SCANA Corporation

Cayce, South Carolina

 We have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, 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, 2009 of the Company and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 1, 2010

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ITEM 9A(T).  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2009, an evaluation was performed under the supervision and with the participation of South Carolina Electric & Gas Company’s (SCE&G) management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures.  For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure.  Based on that evaluation, SCE&G’s management, including the CEO and CFO, concluded that SCE&G’s disclosure controls and procedures were effective as of December 31, 2009.  There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2009 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, 2009, 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, 2009.  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, 2009, internal control over financial reporting is effective based on those criteria.

This annual report does not include an attestation report of SCE&G’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by SCE&G’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit SCE&G to provide only its management’s report in this annual report.

ITEM 9B. OTHER INFORMATION

Not applicable.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

A list of SCANA’s executive officers is in Part I of this annual report at page 24.  The other information required by Item 10 is incorporated herein by reference to the captions "NOMINEES FOR DIRECTORS," "CONTINUING DIRECTORS," "BOARD MEETINGS-COMMITTEES OF THE BOARD," "GOVERNANCE INFORMATION - SCANA’s Code of Conduct & Ethics" and "OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA’s definitive proxy statement for the 2010 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.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated herein by reference to the captions  “COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION,” “COMPENSATION DISCUSSION AND ANALYSIS,” “COMPENSATION COMMITTEE REPORT,” “SUMMARY COMPENSATION TABLE,” “2009 GRANTS OF PLAN-BASED AWARDS,” “OUTSTANDING EQUITY AWARDS AT 2009 FISCAL YEAR-END,”  “2009 OPTION EXERCISES AND STOCK VESTED,”  “PENSION BENEFITS,” “2009 NONQUALIFIED DEFERRED COMPENSATION,” and “POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL,” under the heading “EXECUTIVE COMPENSATION” and the heading “DIRECTOR COMPENSATION” in SCANA’s definitive proxy statement for the 2010 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.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

                  RELATED STOCKHOLDER MATTERS

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 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.

Equity securities issuable under SCANA’s compensation plans at December 31, 2009 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	103,589	27.44	3,138,638
Non-Employee Director Compensation Plan	n/a	n/a	49,668
Equity compensation plans not approved by security holders	n/a	n/a	n/a
Total	103,589	27.44	3,188,306

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 The information required by Item 13 is incorporated herein by reference to the caption “RELATED PARTY TRANSACTIONS” in SCANA’s definitive proxy statement for the 2010 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.

ITEM 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES

SCANA: The information required by Item 14 is incorporated herein by reference to "PROPOSAL 3 - APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM" in SCANA’s definitive proxy statement for the 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities and Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.

126

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 by the Chairman to pre-approve the rendering of services are presented to the Audit Committee at its next scheduled meeting.

Independent Registered Public Accounting Firm’s Fees

The following table sets forth the aggregate fees, all of which were approved by the Audit Committee, charged to SCE&G and its consolidated affiliates for the fiscal years ended December 31, 2009 and 2008 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

		2009		2008
Audit Fees(1)	$	1,676,101	$	1,687,425
Audit-Related Fees(2)		71,375		64,233
Total Fees	$	1,747,476	$	1,751,658

(1) Fees for audit services billed in 2009 and 2008 consisted of audits of annual financial statements, comfort letters,  consents and other services related to Securities and Exchange Commission filings and accounting research.

(2)    Fees primarily for employee benefit plan audits for 2008 and 2007.

127

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)     The following documents are filed or furnished as a part of this Form 10-K:

(1)     Financial Statements and Schedules:

The Report of Independent Registered Public Accounting Firm on the financial statements for SCANA and SCE&G are listed under Item 8 herein.

The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein.

The financial statement schedules filed as part of this report for SCANA and SCE&G are included below.

(2)     Exhibits

Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page.  Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission (SEC) and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.

Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA’s employee stock purchase plan will be furnished under cover of Form 11-K 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.

128

Schedule II—Valuation and Qualifying Accounts

(in millions)

			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
2009	$	11	$	17		$	-	$	19	$	9
2008		10		14			-		13		11
2007		14		9			-		13		10
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2009	$	6	$	4		$	-	$	3	$	7
2008		7		3			-		4		6
2007		9		6			-		8		7
SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2009	$	3	$	6		$	-	$	6	$	3
2008		2		5			-		4		3
2007		5		-			-		3		2
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2009	$	5	$	3		$	-	$	3	$	5
2008		6		3			-		4		5
2007		7		6			-		7		6

129

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:	March 1, 2010

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
	J. W. Martin, III	G. S. York
	J. M. Micali

*Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact

DATE: March 1, 2010

130

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:	March 1, 2010

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	J. W. Roquemore
	S. A. Decker	M. K. Sloan
	D. M. Hagood	H. C. Stowe
	J. M. Micali	G. S. York

*Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact

DATE: March 1, 2010

131

	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 December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.04	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 3.01 to Form 8-K filed February 23, 2009 and incorporated by reference herein)
3.05		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 Mellon Trust Company, N. A. (successor to 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		First Supplemental Indenture to Indenture referred to in Exhibit 4.02 dated as of November 1, 2009 (Filed herewith)
4.04	X		Junior Subordinated Indenture dated as of November 1, 2009 between SCANA Corporation and U.S. Bank National Association, as Trustee (Filed herewith)
4.05	X		First Supplemental Indenture to Junior Subordinated Indenture referred to in Exhibit 4.04 dated as of November 1, 2009 (Filed herewith)
4.06		X	Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to The Bank of New York Mellon Trust Company, N. A. (as successor to NationsBank of Georgia, National Association), as Trustee (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)
4.07		X	First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)
4.08		X	Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)
*10.01	X	X	Engineering, Procurement and Construction Agreement, dated May 23, 2008, between South Carolina Electric & Gas Company, for itself and as Agent for the South Carolina Public Service Authority and a Consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended)  (Filed as Exhibit 10.01 to Form 10-Q/A for the quarter ended June 30, 2008 and incorporated by reference herein)
*10.02	X	X	SCANA Executive Deferred Compensation Plan (including amendments through December 31, 2009) (Filed herewith)
*10.03	X	X	SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) (Filed herewith)

132

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
*10.04	X	X	SCANA Director Compensation and Deferral Plan (including amendments through December 31, 2009) (Filed herewith)
*10.05	X	X	SCANA Long-Term Equity Compensation Plan as amended and restated effective as of January 1, 2009 (Filed as Exhibit 4.04 to Post-Effective Amendment No. 1 to Registration Statement No. 333-37398 and incorporated by reference herein)
*10.06	X	X	SCANA Long-Term Equity Compensation Plan as amended and restated (including amendments through December 31, 2009) (Filed as Exhibit 99.01 to Form 8-K filed February 10, 2010 and incorporated by reference herein)
*10.07	X	X	SCANA Supplementary Executive Benefit Plan (including amendments through December 31, 2009) (Filed herewith)
*10.08	X	X	SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) (Filed herewith)
*10.09	X	X	SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) (Filed herewith)
*10.10	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)
10.11		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		Power of Attorney (Filed herewith)
24.02		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)

133

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	Description
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

134