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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. SCANA Corporation ý South Carolina Electric & Gas Company ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. SCANA Corporation o South Carolina Electric & Gas Company o

Indicate by check mark whether the registrant: (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. SCANA Corporation Yes ý No o South Carolina Electric & Gas Company Yes ý No o

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 ý No o South Carolina Electric & Gas Company Yes o No o

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

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).

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes o No ý South Carolina Electric & Gas Company Yes o No ý

The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $4.5 billion at June 30, 2010 based on the closing price of $35.76 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:

Documents incorporated by reference: Specified sections of SCANA Corporation's Proxy Statement, in connection with its 2011 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 registrant is filed by such registrant on its own behalf. Each registrant 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).

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," "forecasts," "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:

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

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
	ARO		Asset Retirement Obligation
	BLRA		Base Load Review Act
	CAA		Clean Air Act, as amended
	CAIR		Clean Air Interstate Rule
	CAMR		Clean Air Mercury Rule
	CCR		Coal Combustion Residuals
	CEO		Chief Executive Officer
	CFO		Chief Financial Officer
	CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
	CGT		Carolina Gas Transmission Corporation
	COL		Combined Construction and Operating License
	Company		SCANA, together with its consolidated subsidiaries
	Consolidated SCE&G		SCE&G and its consolidated affiliates
	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.
	DOT		United States Department of Transportation
	DSM Programs		Demand Side Management Programs
	DT		Dekatherm (one million BTUs)
	EIZ Credits		South Carolina Economic Impact Zone Income Tax Credits
	Energy Marketing		The divisions of SEMI, excluding SCANA Energy
	EPA		United States Environmental Protection Agency
	eWNA		Pilot Electric WNA
	FERC		United States Federal Energy Regulatory Commission
	Fitch		Fitch Ratings
	Fuel Company		South Carolina Fuel Company, Inc.
	GENCO		South Carolina Generating Company, Inc.
	GHG		Greenhouse Gas
	GPSC		Georgia Public Service Commission
	IRS		Internal Revenue Service
	JEDA		The South Carolina Job-Economic Development Authority
	KVA		Kilovolt ampere
	kW or kWh		Kilowatt or Kilowatt-hour
	LLC		Limited Liability Company
	LNG		Liquefied Natural Gas
	LOC		Lines of Credit
	MACT		Maximum Achievable Control Technology
	MCF or MMCF		Thousand Cubic Feet or Million Cubic Feet
	MGP		Manufactured Gas Plant
	MMBTU		Million British Thermal Units

TERM			MEANING

	MW or MWh		Megawatt or Megawatt-hour
	Moody's		Moody's Investors Service
	NASDAQ		The NASDAQ Stock Market, Inc.
	NERC		North American Electric Reliability Corporation
	New Units		Nuclear Units 2 and 3 to be constructed at Summer Station
	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
	NYSE		The New York Stock Exchange
	OATT		Open Access Transmission Tariff
	ORS		South Carolina Office of Regulatory Staff
	PGA		Purchased Gas Adjustment
	Pipeline Safety Act		The Pipeline Safety Improvement Act of 2002
	PHMSA		Pipeline Hazardous Materials Safety Administration
	Plan		SCANA Long-Term Equity Compensation Plan
	PRP		Potentially Responsible Party
	PSNC Energy		Public Service Company of North Carolina, Incorporated
	RCC		Replacement Capital Covenant
	RCRA		Resource Conservation and Recovery Act
	RES		Renewable Energy Standard
	RSA		Natural Gas Rate Stabilization Act
	S&P		Standard & Poor's Rating Services
	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
	TSR		Total Shareholder Return
	Westinghouse		Westinghouse Electric Company LLC
	Williams Station		A.M. Williams Generating Station, owned by GENCO
	WNA		Weather Normalization Adjustment
	VACAR		Virginia-Carolinas Reliability Group
	VIE		Variable Interest Entity

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.

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

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.

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.

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, 2011 and 2010 of 5,877 and 5,828, 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, 2011 and 2010 of 3,173 and 3,108, respectively.

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.

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.

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 660,600 customers and the purchase, sale and transportation of natural gas to approximately 313,500 customers (each as of December 31, 2010). 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 approximately 22,600 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, paper products, food products, lumber and wood products, health services, textile manufacturing, rubber and miscellaneous plastic products and fabricated metal products.

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 482,000 residential, commercial and industrial customers (as of December 31, 2010). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The predominant industries served by PSNC Energy include educational services, food products, health services, chemicals, non-woven textiles and construction related materials.

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.

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 approximately 460,000 customers (as of December 31, 2010) in Georgia's natural gas market. The GPSC has selected SCANA Energy to serve as the state's regulated provider until August 31, 2012. Included in the above customer count, SCANA Energy serves approximately 90,000 customers (as of December 31, 2010) 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.

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.

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.

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 2011-2013, 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 2.92, 2.84, 3.04, 3.03 and 2.94 for the years ended December 31, 2010, 2009, 2008, 2007 and 2006, respectively. SCE&G's ratios of earnings to fixed charges were 3.18, 3.25, 3.51, 3.40 and 3.32 for the same periods.

SCE&G's sales of electricity and margins earned from the sale of electricity by customer classification as a percent of electric revenues for 2009 and 2010 were as follows:

Sales for resale include sales to three municipalities and two electric cooperatives. Sales under NMST during 2010 include sales to eight investor-owned utilities or registered marketers, two electric cooperatives and three federal/state electric agencies. During 2009 sales under the NMST included sales to nine investor-owned utilities or registered marketers, three electric cooperatives and three federal/state electric agencies.

During 2010 SCE&G recorded a net increase of approximately 5,600 electric customers (growth rate of 0.9%), increasing its total electric customers to approximately 660,600 at year end.

For the period 2011-2013, SCE&G projects total territorial KWh sales of electricity to increase 1.3% annually (assuming normal weather), total electric customer base to increase 1.7% annually and territorial peak load (summer, in MW) to increase 1.8% 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.

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 605 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 (Thurmond) Project. SCE&G, Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Dominion Virginia Power and ALCOA Power Generating, Inc. (Yadkin Division), are members of VACAR, one of several geographic divisions within the SERC. SERC is one of eight regional entities with delegated authority from 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.

The average cost of various fuels and the weighted average cost of all fuels (including oil) for the years 2008-2010 follow:

The sources and percentages of total MWh generation by each category of fuel for the years 2008-2010 and the estimates for the years 2011-2013 follow:

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

During 2009, as coal costs increased and gas prices decreased, 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 suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 4.0 million tons annually, which is substantially all expected coal purchases for 2011. Sulfur restrictions on the contract coal range from 1% to 2%. These contracts expire at various times through 2014. 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 oxide. See additional discussion at Environmental Matters in Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under

these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G's exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation in 2016 and 2019, respectively.

In addition to the above-described contracts for fuel fabrication and related services, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates in the next 11 years. SCE&G believes that it will be able to renew contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of its nuclear generating units.

SCE&G can store spent nuclear fuel on-site until at least 2017 and expects to expand its storage capacity to accommodate the spent fuel output for the life of Summer Station Unit 1 through dry cask storage or other technology as it becomes available. In addition, Summer Station Unit 1 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.

Regulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 2009 and 2010 were as follows:

For the three-year period 2011-2013, SCANA projects total consolidated sales of regulated natural gas in DTs to increase 1.7% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 1.8%, commercial of 0.8% and industrial of 2.0%.

For the three-year period 2011-2013, SCE&G projects total consolidated sales of regulated natural gas in DTs to increase 0.4% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 0.6%, commercial of 0.2% and industrial of 0.7%.

For the three-year period 2011-2013, SCANA's and SCE&G's total consolidated regulated natural gas customer base is projected to increase annually 1.9% and 1.2%, respectively. During 2010 SCANA recorded a net increase of approximately 12,600 regulated gas customers (growth rate of 1.6%), increasing its regulated gas customers to approximately 794,800. Of this increase, SCE&G recorded a net increase of approximately 3,677 gas customers (growth rate of 1.2%), increasing its total gas customers to approximately 313,500 (as of December 31, 2010).

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

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 2013), 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 $6.38 per MCF during 2010 and $7.01 per MCF during 2009.

SCE&G was allocated 5,437 MMCF of natural gas storage capacity on Southern Natural and Transco. Approximately 3,892 MMCF of gas were in storage on December 31, 2010. 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 1,558 MMCF (liquefied equivalent) of gas were in storage on December 31, 2010.

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 279,894 DT from Transco and 7,331 DT from Dominion.

PSNC Energy purchased natural gas at an average cost of $5.95 per DT during 2010 compared to $6.02 per DT during 2009.

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 9,200 MMCF of gas were in storage under these agreements at December 31, 2010. 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 700 MMCF (liquefied equivalent) of gas were in storage at December 31, 2010. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 800 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2010.

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.

SEMI markets natural gas and provides energy-related risk management services primarily in the Southeast. In addition, SCANA Energy, a division of SEMI, markets natural gas to approximately 460,000 customers (as of December 31, 2010) 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.

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.

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 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 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 $1.2 billion of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $150 million of such short-term indebtedness. The authority to make such issuances will expire in October 2012.

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

SCE&G is presently operating the Saluda project under an annual license (scheduled to expire in August) while its application to FERC for a long-term license is pending. SCE&G's re-licensing application is currently being reviewed by FERC.

At the termination of a license under the Federal Power Act, FERC may extend or issue a new license to the previous licensee, 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.

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

SCE&G's gas rate schedules for its residential, small commercial and small industrial customers include a WNA 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 which allows PSNC Energy to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption whether impacted by weather or other factors.

On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G's retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC's order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other things, the SCPSC's order (1) included implementation of an eWNA for SCE&G's electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G's customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and ORS, (3) provided for a $48.7 million credit to SCE&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including 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's order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the DSM rate rider tariff sheet with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings before the SCPSC regarding the DSM programs, net lost revenues, program costs, incentive and net program benefits.

In January 2010, the SCPSC approved SCE&G's request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of the New 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. The revised schedule does not change the previously announced completion date for the New Units or the originally announced cost.

In February 2009, the SCPSC approved SCE&G's combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New 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 as approved by the SCPSC.

In May 2009, two intervenors filed separate appeals of the order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC's prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC's decision to allow SCE&G to include a pre-approved cost contingency amount associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G's share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million of the anticipated capital costs (in 2007 dollars) represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court's ruling, however, does not affect the project schedule or disturb the SCPSC's issuance of a certificate of environmental compatibility and public convenience and necessity, which is necessary to construct the New Units. On November 15, 2010, SCE&G filed a petition to the SCPSC seeking an order approving an updated capital cost schedule for the construction of the company's New Units that reflects the removal of the contingency reserve and incorporates

presently identifiable additional capital costs of $173.9 million. A hearing on this petition is scheduled for April 4, 2011, and the SCPSC is expected to rule on the request in May 2011.

Under the BLRA, 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 October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA. The new retail electric rates were effective for bills rendered on and after October 30, 2010. In November 2010 SCE&G filed its quarterly report updating the status of the project including capital costs and the construction schedule.

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 concerning its fuel costs at any time should circumstances dictate such a review.

SCE&G's electric 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. Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&G's proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of undercollected fuel costs. In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011. SCE&G is allowed to charge and recover carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.

SCE&G's natural gas tariffs include a 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 12-month rolling average. The annual PGA hearing to review SCE&G's gas purchasing policies and procedures was conducted in November 2010 before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2009 through July 31, 2010, were reasonable and prudent.

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.

In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy's rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy's rates. The rate adjustment was effective with the first billing cycle in March 2010.

In October 2010, in connection with PSNC Energy's 2010 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, 2010.

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 10 to the consolidated financial statements for SCANA and SCE&G.

For a discussion of SCE&G's insurance coverage for Summer Station Unit 1, see Note 10 to the consolidated financial statements for SCANA and SCE&G.

The risk factors that follow relate in each case to SCANA and its subsidiaries, and where indicated the risk factors also relate to SCE&G and its consolidated affiliates.

Commodity price changes, delays and other factors may affect the operating cost, capital expenditures and competitive positions of the Company's and Consolidated 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 prudently incurred 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 addition, increased inventories of coal, with attendant increased carrying cost, may result when natural gas prices are low enough, relative to coal, to require the dispatch of gas-fired electric generation ahead of coal-fired electric generation. This may adversely affect our results of operations, cash flows and financial position.

In the case of regulated natural gas operations, costs prudently incurred 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, and 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.

The costs of large capital projects, such as the Company's and Consolidated SCE&G's construction for environmental compliance and its construction of the New Units and associated transmission, 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 Consolidated SCE&G's businesses are capital intensive and require significant investments in energy generation and in other internal infrastructure projects, including projects for environmental compliance. For example, SCE&G and Santee Cooper have agreed to jointly own, design, construct and operate the New Units, which consist of two new 1,117-megawatt nuclear units at SCE&G's Summer Station, 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 plants upon receipt of requisite approvals. Associated with the construction of the New Units and an integral part of the project is the construction of additional transmission. 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 or non-compliance with regulatory requirements, 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 and a new partner cannot be attracted to the project at equivalent financial terms or that a change in joint venture partners or the addition of a new joint venture partner will increase project costs or delay the commercial operation dates of the joint venture project. 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 Consolidated 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 Consolidated 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 Consolidated 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 Consolidated 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 Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, the NRC, the SEC, the Internal Revenue Service, the EPA, PHMSA, and a number of others. In addition, the Company and Consolidated 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 Consolidated 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, siting, construction and operation 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 Consolidated SCE&G's businesses.

The Company and Consolidated 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, SCE&G's electric transmission system and Consolidated SCE&G's generating facilities are subject to extensive regulation and oversight from 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 Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and which may impact our business plans or expose us to environmental liabilities.

The Company and Consolidated 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). We expect that some form of regulation will be forthcoming at the federal, and possibly state, levels to impose limitations on 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 CAMR. The EPA is expected to implement MACT 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 renewable portfolio 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 or more extensive permitting requirements or additional regulatory requirements are imposed.

Furthermore, 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 Consolidated 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 Consolidated 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 Consolidated 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 satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.

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 Consolidated 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 Consolidated 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 Consolidated 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 the Company's and Consolidated SCE&G's results of operations, cash flows and financial position, including its shareholders' equity.

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

S&P, Moody's and Fitch rate SCANA's long-term senior unsecured debt at BBB, Baa2 and BBB+, respectively, and rate SCANA's junior subordinated notes 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, and rate SCE&G's unsecured debt at BBB+, Baa1 and A-, respectively. S&P, Moody's and Fitch rate the long-term senior unsecured debt of PSNC Energy at BBB+, A3 and A-, respectively. Moody's carries a negative outlook on each of its ratings. S&P and Fitch each carry a stable outlook on each of their ratings.

SCANA's leverage ratio of debt to capital was approximately 57% at December 31, 2010. SCANA has publicly announced its desire to maintain its leverage ratio at 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 maintain its leverage ratio within the desired range, SCANA's and SCE&G's debt ratings may be affected.

If S&P, Moody's or Fitch were to downgrade any of these long-term ratings, particularly to below investment grade, borrowing costs would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease. S&P, Moody's and Fitch rate the short-term debt of SCANA, 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.

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. During 2010, the SCPSC approved SCE&G's implementation of the eWNA on a one-year pilot basis. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and, if the eWNA is not extended on a permanent basis, SCE&G. In addition, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

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

The utility industry has been undergoing structural change for a number of 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 Consolidated 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 Consolidated 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. Similarly, a gas transmission or distribution line failure of the Company or SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers. Events such as these could entail substantial

repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company's revenues, results of operations, and financial condition.

SCANA's ability to pay dividends and to make payments on SCANA's debt securities may be limited by covenants in certain financial instruments and by the financial results and condition of its subsidiaries, thereby adversely impacting the valuation of our common stock and our access to capital .

We are a holding company that conducts substantially all of our operations through our subsidiaries. Our assets consist primarily of investments in subsidiaries. Therefore, our ability to meet our obligations for payment of interest and principal on outstanding debt and to pay dividends to shareholders and corporate expenses depend on the earnings, cash flows, financial condition and capital requirements of our subsidiaries, and the ability of our subsidiaries, principally SCE&G, PSNC Energy and SEMI to pay dividends or to advance or repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.

A significant portion of Consolidated 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 2010, Summer Station Unit 1, operated by SCE&G, provided approximately 5.7 million MWh, or 21% 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 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 Consolidated 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 Consolidated 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 Consolidated 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 Consolidated SCE&G. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company's or Consolidated SCE&G's interests, may have a negative effect on our results of operations, cash flows and financial position, as well as limit our ability to access capital.

The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure of our 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 Consolidated SCE&G's access to capital.

The Company and Consolidated 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 Consolidated SCE&G also are committed to operational excellence and, through our Code of Conduct and Ethics, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments may subject the Company and Consolidated 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 Consolidated SCE&G's access to capital, and result in further regulatory oversight.

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.

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

Facility	Present Fuel Capability	Location	Year In-Service

Steam Turbines:
Summer(1)	Nuclear	Jenkinsville, 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	605
Cope	Coal	Cope, SC	1996	410
Kapstone(3)	Biomass/Coal	Charleston, SC	1999	90
Combined Cycle:
Urquhart(4)	Coal/Gas/Oil	Beech Island, SC	1953/2002	553
Jasper	Gas/Oil	Hardeeville, SC	2004	872
Hydro(5):
Saluda		Irmo, SC	1930	200
Fairfield Pumped Storage		Jenkinsville, SC	1978	576

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 2010 and have aggregate net generating capacity of 355 MW.

SCE&G owns 441 substations having an aggregate transformer capacity of 29 million KVA. The transmission system consists of 3,287 miles of lines, and the distribution system consists of 18,249 pole miles of overhead lines and 6,659 trench miles of underground lines.

SCE&G's natural gas system consists of 16,182 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 1,467 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 589 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 10,063 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.

Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2010, are described below. These issues affect SCANA and, to the extent indicated, also affect Consolidated SCE&G.

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 May 13, 2010, the EPA finalized the GHG Tailoring Rule, which sets thresholds for GHG emissions that define when permits under the New Source Review, the Prevention of Significant Deterioration, and the Title V Operation Permits programs are required for new and existing facilities (such as SCE&G's and GENCO's generating facilities). The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

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 has installed a wet limestone scrubber at Wateree Station for sulfur dioxide reduction. GENCO has completed installation of a wet limestone scrubber at Williams Station. EPA has proposed a revised rule which is currently being evaluated by the Company. 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 June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide emissions. Initial evaluation of this new standard indicated that SCE&G's McMeekin Station in Lexington County may be required to reduce its sulfur dioxide emissions to a level determined by EPA and/or DHEC. The costs incurred to comply with this new standard are expected to be recovered through rates.

units. The Company expects the EPA will issue a new rule on mercury emissions in 2011 but cannot predict what requirements it will impose.

SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G's allocation will not 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 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 cleanup. 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 cleanup relate solely to regulated operations. SCE&G defers site assessment and clean-up costs and expects to recover them through rates.

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 DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $8.9 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 through rates. At December 31, 2010, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $26.4 million and are included in regulatory assets.

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 $4.2 million, the estimated remaining liability at December 31, 2010. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been tentatively settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. The parties are proceeding to identify class members and resolve other settlement related issues. While this settlement is subject to a fairness hearing before it is finally approved, SCE&G and SCI currently know of no reason why such approval will not be given. This tentative settlement will not have a material adverse impact on the Company's 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.

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		Positions Held During Past Five Years	Dates

William B. Timmerman	64	Chairman of the Board and Chief Executive Officer President	-present -2011
Jimmy E. Addison	50	Senior Vice President and Chief Financial Officer Vice President—Finance	2006 - present *-2006
Jeffrey B. Archie	53	Senior Vice President and Chief Nuclear Officer Senior Vice President—Nuclear Operations Vice President of Nuclear Plant Operations	2010 - present 2009 - 2010 *-2009
George J. Bullwinkel	62	President and Chief Operating Officer—SEMI, SCI and ServiceCare	*-present
Sarena D. Burch	53	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	51	Executive Vice President—Generation and Transmission and Chief Operating Officer—SCE&G Executive Vice President—Generation, Nuclear and Fossil Hydro—SCE&G Senior Vice President—Generation, Nuclear and Fossil Hydro—SCE&G	2011 - present 2009 - 2011 *-2009
Paul V. Fant	57	President and Chief Operating Officer—CGT Senior Vice President—SCANA Senior Vice President—Transmission Services—SCE&G	-present 2008 - present -2007
Ronald T. Lindsay	60	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	55	President and Chief Operating Officer President—SCE&G Chief Operating Officer—SCE&G Senior Vice President and Chief Financial Officer	2011 - present 2006 - present 2006 - 2011 *-2006
Charles B. McFadden	66	Senior Vice President—Governmental Affairs and Economic Development—SCANA Services	*-present

On January 7, 2011 William B. Timmerman announced his retirement as Chairman of the Board and Chief Executive Officer effective November 30, 2011. The Board of Directors has elected Kevin B. Marsh to assume these positions effective upon Mr. Timmerman's retirement.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

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, 2011 there were 127,875,625 shares of SCANA Common Stock outstanding which were held by approximately 30,106 shareholders of record. For a summary of equity securities issuable under SCANA's compensation plans at December 31, 2010, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

SCANA declared quarterly dividends on its common stock of $.475 per share in 2010 and $.47 per share in 2009. On February 11, 2011, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.485 per share, an increase of 2.1%. The new dividend is payable April 1, 2011 to shareholders of record on March 10, 2011. 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 3 to the consolidated financial statements for SCANA.

All of SCE&G's common stock is owned by SCANA, and no established public trading market exists for SCE&G common stock. During 2010 and 2009, SCE&G declared quarterly dividends on its common stock in the following amounts:

On February 11, 2011, SCE&G declared dividends on its common stock of $49.0 million.

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 3 to the consolidated financial statements for SCE&G.

As of or for the Year Ended December 31,		2010			2009			2008			2007			2006

		(Millions of dollars, except statistics and per share amounts)
SCANA:
Statement of Income Data
Operating Revenues		$	4,601		$	4,237		$	5,319		$	4,621		$	4,563
Operating Income		$	768		$	699		$	710		$	633		$	603
Other Income (Expense)		$	(234	)	$	(177	)	$	(176	)	$	(153	)	$	(157	)
Preferred Stock Dividends		$	—		$	(9	)	$	(7	)	$	(7	)	$	(7	)
Income Before Cumulative Effect of Accounting Change(1)		$	376		$	348		$	346		$	320		$	304
Income Available to Common Shareholders(1)(2)		$	376		$	348		$	346		$	320		$	310
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions)			125.7			122.1			117.0			116.7			115.8
Basic Earnings Per Share(1)(2)		$	2.99		$	2.85		$	2.95		$	2.74		$	2.68
Diluted Earnings Per Share(1)(2)		$	2.98		$	2.85		$	2.95		$	2.74		$	2.68
Dividends Declared Per Share of Common Stock		$	1.90		$	1.88		$	1.84		$	1.76		$	1.68
Balance Sheet Data
Utility Plant, Net		$	9,662		$	9,009		$	8,305		$	7,538		$	7,007
Total Assets		$	12,968		$	12,094		$	11,502		$	10,165		$	9,817
Total Equity		$	3,702		$	3,408		$	3,045		$	2,960		$	2,846
Short-term and Long-term Debt		$	4,909		$	4,846		$	4,698		$	3,852		$	3,711
Other Statistics
Electric:
	Customers (Year-End)		660,580			654,766			649,571			639,258			623,402
	Total sales (Million KWh)		24,884			23,104			24,284			24,885			24,519
	Generating capability—Net MW (Year-End)		5,645			5,611			5,695			5,749			5,749
	Territorial peak demand—Net MW		4,735			4,557			4,789			4,926			4,742
Regulated Gas:
	Customers, excluding transportation (Year-End)		794,841			782,192			774,502			759,336			738,317
	Sales, excluding transportation (Thousand Therms)(3)		931,879			832,931			848,568			823,976			997,173
	Transportation customers (Year-End)(3)		491			482			474			446			430
	Transportation volumes (Thousand Therms)(3)		1,546,234			1,388,096			1,366,675			1,369,684			852,100
Retail Gas Marketing:
	Retail customers (Year-End)		464,123			455,198			459,250			484,565			482,822
	Firm customer deliveries (Thousand Therms)		402,583			347,324			356,288			340,743			335,896
Nonregulated interruptible customer deliveries (Thousand Therms)			1,728,161			1,628,942			1,526,933			1,548,878			1,239,926
SCE&G:
Statement of Income Data
Operating Revenues		$	2,815		$	2,569		$	2,816		$	2,481		$	2,391
Operating Income		$	604		$	547		$	559		$	498		$	468
Other Income (Expense)		$	(168	)	$	(119	)	$	(122	)	$	(117	)	$	(121	)
Preferred Stock Dividends		$	—		$	(9	)	$	(7	)	$	(7	)	$	(7	)
Income Before Cumulative Effect of Accounting Change		$	290		$	281		$	273		$	245		$	230
Income Available to Common Shareholders(2)		$	290		$	281		$	273		$	245		$	234
Balance Sheet Data
Utility Plant, Net		$	8,198		$	7,595		$	6,905		$	6,202		$	5,748
Total Assets		$	10,574		$	9,813		$	9,052		$	7,977		$	7,626
Total Equity		$	3,541		$	3,259		$	2,799		$	2,711		$	2,543
Short-term and Long-term Debt		$	3,440		$	3,430		$	3,320		$	2,593		$	2,498
Other Statistics
Electric:
	Customers (Year-End)		660,642			654,830			649,636			639,312			623,453
	Total sales (Million KWh)		24,887			23,107			24,287			24,888			24,538
	Generating capability—Net MW (Year-End)		5,645			5,611			5,695			5,749			5,749
	Territorial peak demand—Net MW		4,735			4,557			4,789			4,926			4,742
Regulated Gas:
	Customers, excluding transportation (Year-End)		313,346			309,687			307,074			302,469			297,165
	Sales, excluding transportation (Thousand Therms)		447,057			399,752			416,075			407,204			403,489
	Transportation customers (Year-End)		148			130			120			115			100
	Transportation volumes (Thousand Therms)		190,931			217,750			64,034			27,113			24,845

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

SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and sale of electricity in parts of South Carolina and 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.

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.

During 2010, the lingering effects of an economic recession showed modest signs of improvement in the southeast. At December 31, 2010 a preliminary estimate of seasonally adjusted unemployment nationwide was 9.4% compared to comparable unemployment rates in the states in which the Company primarily provides service (10.2% in Georgia, 9.8% in North Carolina and 10.7% in South Carolina). Though improved from December 2009, these unemployment rates remain stubbornly high and indicate that economic recovery in the southeast lags the nation. Customer growth rates in the Company's regulated and retail gas business segments were slightly positive in 2010, though customer usage within the regulated business segments continued to decline. The Company expects customer growth to be similar and usage patterns to continue in 2011.

Over the next five years, key earnings drivers for the Company will be additions to rate base at its regulated subsidiaries, consisting primarily of capital expenditures for new generating capacity, environmental facilities 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.

The electric operations segment is comprised of the electric operations of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 2010 SCE&G provided electricity to approximately 660,600 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 allowances.

Operating results for electric operations are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G's allowed return on equity is 10.7% for non-BLRA expenditures, and 11.0% for BLRA-related expenditures. 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.

SCE&G, for itself and as agent for Santee Cooper, has contracted with Westinghouse and Stone & Webster, Inc. for the design and construction of the New Units at the site of Summer Station. The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G's need for 55% of the output of the two units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has more recently indicated that it will seek to reduce its 45% ownership in the New Units. If Santee Cooper's ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.

The successful completion of the project would result in a substantial increase of the Company's utility plant in service. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.

SCE&G expects to receive a COL for the New Units from the NRC in late 2011 or early 2012, which would support both the project schedule and the substantial completion dates for the New Units in 2016 and 2019, respectively. Environmental and safety reviews by the NRC are currently in progress and are part of the NRC's 30-month review schedule which began July 31, 2008.

In 2009, the SCPSC approved SCE&G's combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New 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 as approved by the SCPSC.

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G's exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation in 2016 and 2019, respectively.

The Company expects that significant federal legislative initiatives related to energy, will be hampered through 2012 due to each chamber of Congress being controlled by different political parties. Significant regulatory initiatives by the EPA and other federal agencies, however, will likely proceed. 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 an RES). 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 initiatives 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 CCR, such as ash. Such regulations could result in the treatment of some CCRs 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 gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy and is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of North Carolina and South Carolina. At December 31, 2010 this segment provided natural gas to approximately 795,500 customers in areas covering 34,600 square miles.

Operating results for gas distribution are primarily influenced by customer demand for natural gas rates allowed to be charged to customers and the ability to control growth in costs. 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. One effect of the recent economic recession was an overall decrease in demand for natural gas which, coupled with discoveries of shale gas in the United States, resulted in significantly lower prices for this commodity in 2009 and 2010.

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to approximately 460,000 customers (as of December 31, 2010, 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 an affiliate of a large energy company 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 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 is for a term ending August 31, 2012. 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 approximately 90,000 customers (as of December 31, 2010).

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 6 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.

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

The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control growth of 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.


• 2010 vs 2009		Basic earnings per share increased in 2010 due to higher electric margin (excluding the effect of the $17.4 million adjustment described at "Electric Operations") of $.60 and higher gas margin of $.15. These increases were partially offset by dilution from additional shares outstanding of $.09, higher operating expense of $.32, higher interest expense of $.09, net of preferred stock dividends, and $.11 due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in favor of the Company in 2009. In late 2009 SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.
• 2009 vs 2008		Basic 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.

In May 2010, SCANA entered into equity forward sales contracts for approximately 6.6 million common shares. During periods when the average market price of SCANA's common stock is above the per share adjusted forward sales price, the Company computes diluted earnings per share giving effect to this dilutive potential common stock utilizing the treasury stock method. The dilutive effect was $.01 per share for the year ended December 31, 2010.

Pension cost (income) was recorded on the Company's income statements and balance sheets as follows:

SCPSC allowed SCE&G to mitigate a significant portion of pension cost by deferring as a regulatory asset the amount of pension expense above the level of pension income which was included in rates. This pension cost arose due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets. The Company had recorded significant pension income in 2008.

No contribution to the pension trust was necessary, nor did limitations on benefit payments apply, in or for any period reported.

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 5.6% of income before income taxes in 2010, 9.8% in 2009 and 5.6% in 2008, respectively.

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


• 2010 vs 2009		Margin increased by $37.0 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $30.7 million due to an increase in base rates approved by the SCPSC under the BLRA. In addition, margin increased by $54.2 million (net of eWNA after its implementation) due to weather, by $5.8 million due to higher transmission revenue and off-system sales and by $13.6 million due to the adoption of SCPSC-approved lower electric depreciation rates in 2009, the effect of which was offset by a reduction in the recovery of fuel costs (electric revenue). During the first quarter of 2010, the Company deferred $25 million of incremental revenue as a result of the abnormally cold weather in SCE&G's service territory (see Note 2 to the consolidated financial statements). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G's annual fuel cost proceeding. (See also discussion at "Income Taxes".) Finally, pursuant to the SCPSC-approved retail electric base rate order in 2010, SCE&G adopted an eWNA thereby mitigating the effects of abnormal weather on its margins.

Sales volumes (in MWh) related to the electric margin above, by class, were as follows:

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

Retail Gas Marketing is comprised of SCANA Energy which operates in Georgia's natural gas market. Retail Gas Marketing revenues and income available to common shareholders were as follows:

Energy Marketing is comprised of the Company's nonregulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and income available to common shareholders were as follows:


• 2010 vs 2009		Other operation and maintenance expenses increased by $17.7 million due to higher generation, transmission and distribution expenses, by $10.9 million due to higher incentive compensation and other benefits and by $6.1 million due to higher customer service expenses and general expenses, including bad debt expense. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.
• 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 net property additions. Other taxes increased primarily due to higher property taxes.

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:

In September 2009, as a result of a favorable decision by the South Carolina Supreme Court regarding SCE&G's EIZ Credits, SCE&G recorded the refund of the previously contested EIZ Credits of $15.3 million and an additional $14.3 million of interest income. SCE&G recorded a multi-year catch-up 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 interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.

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

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 tax expense (and the effective tax rate) decreased in 2010 primarily due to the recognition of certain previously deferred state income tax credits pursuant to both the settlement of a fuel cost proceeding in the first quarter of 2010 and the retail electric base rate increase in July 2010. (See Note 5 to the consolidated financial statements for reconciling differences between income tax expense and statutory tax expense.) Income tax expense decreased in 2009 primarily due to the resolution of the contested EIZ Credits in favor of the Company (see discussion above at Other Income (Expense)) and changes in operating income.

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, 2010 was 2.92.

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 the original issuance of shares, rather than being purchased on the open market. This provided approximately $94 million of additional equity during 2010 and is expected to provide approximately $95 million in 2011. Due primarily to new nuclear construction plans, the Company anticipates keeping this strategy in place for the foreseeable future.

The Company also expects to issue common stock under forward contracts executed in 2010. In order to facilitate the issuance of additional equity to fund capital expenditures for normal operations and new nuclear as well as to provide shares for issuance under compensation plans and for future business opportunities that may require the issuance of common stock, at the 2011 Annual Meeting, our Board is proposing to amend SCANA's articles of incorporation to increase the number of shares of common stock which are authorized for issuance from 150,000,000 to 200,000,000.

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC, were $876 million in 2010 and are estimated to be $1.1 billion in 2011.

The Company's current estimates of its capital expenditures for construction and nuclear fuel for 2011-2013, which are subject to continuing review and adjustment, are as follows:

The Company's contractual cash obligations as of December 31, 2010 are summarized as follows:

Included in the table above in purchase obligations is SCE&G's portion of a contractual agreement for the design and construction of the new units at the Summer Station site. SCE&G expects to be a joint owner and share operating costs and generation output of the new units, with SCE&G accounting for 55 percent of the cost and output and the other joint owner(s) 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, 2010, obligations arising from these contracts are included in the purchase obligations within the Contractual Cash Obligations table above.

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 10 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 significant contributions are anticipated until after 2011. Cash payments under the health care and life insurance benefit plan were $11.7 million in 2010, and such annual payments are expected to be the same or increase up to $14.1 million in the future.

In addition, the Company is party to certain 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, 2010, the Company had posted $1.9 million in cash collateral for such contracts. In addition, the Company had posted $20 million in cash collateral for interest rate derivative contracts.

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

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. 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 $1.2 billion of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $150 million of short-term indebtedness. The authority to make such issuances will expire in October 2012.

On October 25, 2010, SCANA, SCE&G (including Fuel Company) and PSNC Energy entered into Five-Year Credit Agreements in the amounts of $300 million, $1.1 billion (of which $400 million relates to Fuel Company) and $100 million, respectively, which are scheduled to expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program, and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. 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 SCANA, SCE&G (including Fuel Company) and PSNC Energy.

At December 31, 2010 and 2009, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

As of December 31, 2010, the Company had not borrowed from its $1.5 billion credit facilities, had approximately $420 million in commercial paper borrowings outstanding, was obligated under $3.3 million in LOC supported letters of credit, and held approximately $52 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. Average short-term borrowings outstanding during 2010 were approximately $330 million. Short-term cash needs were met through a variety of methods in the first part of 2010, including issuance of commercial paper and draws against credit facilities. By year end, all short-term needs were being met with commercial paper due to more favorable interest rates and market liquidity.

At December 31, 2010, the Company had net available liquidity of approximately $1.1 billion. The Company's long-term debt portfolio has a weighted average maturity of almost 15 years and bears an average cost of 6.4%. 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.

The Company's articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCANA's junior subordinated indenture (relating to the hereinafter defined Hybrids), SCE&G's bond indenture (relating to the hereinafter defined Bonds) and PSNC Energy's note purchase and debenture purchase agreements 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, 2010, approximately $58 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

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

SCANA has outstanding $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 of debt to capital. 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.

In connection with the Hybrids, SCANA executed an 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.

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, 2010, the Bond Ratio was 5.36.

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire PSNC Energy's $150 million medium term notes due February 15, 2011. In January 2011, SCE&G issued $250 million of 5.45% first mortgage bonds maturing on February 1, 2041. Proceeds from the sale were used to retire SCE&G's $150 million First Mortgage Bonds due February 1, 2011 and for general corporate purposes. The

borrowings refinanced by these 2011 issuances are classified within Long-term Debt, Net in the consolidated balance sheet.

During 2010 the Company experienced net cash outflows related to financing activities of approximately $33 million primarily due to repayment of long-term debt and payment of dividends, partially offset by issuances of common stock and short and long-term debt.

In March 2010, PSNC Energy issued $100 million of 6.54% unsecured notes due March 30, 2020. Proceeds from these notes were used to pay down short-term debt and for general corporate purposes.

On May 17, 2010, SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering and entered into forward sale agreements of approximately 6.6 million shares to be sold over the subsequent 22 months. There have been no shares issued under the forward sale agreements.

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

In February 2011, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.485 per share, an increase of 2.1% from the prior declared dividend. The dividend is payable April 1, 2011 to shareholders of record on March 10, 2011.

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 CAA, CAIR, CWA, Nuclear Waste Act and the 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, 2010, the Company's capital expenditures for environmental control equipment at its fossil fuel generating stations totaled $373.9 million. In addition, the Company made expenditures to operate and maintain environmental control equipment at its fossil plants of $6.5 million during 2010, $5.6 million during 2009, and $5.8 million during 2008, which are included in "Other operation and maintenance" expense and made expenditures to handle waste ash of $5.9 million in 2010, $6.5 million in 2009, and $4.9 million in 2008, which are included in "Fuel used in electric generation." In addition, included within "Other operation and maintenance" expense is annual amortization of $1.4 million in each of 2010, 2009, and 2008 related to SCE&G's recovery of MGP remediation costs as approved by the SCPSC. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $14.5 million for 2011 and $113.3 million for the four-year period 2011-2015. 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 GHG emissions and require electric utilities to generate an increasing percentage of their power from renewable sources. The United States Senate considered but did not pass legislation that would address GHG emissions and would establish an RES. The Company cannot predict if or when any such energy legislation 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 2010. The Company cannot predict whether such legislation will be introduced or enacted in 2011, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.

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 the New Units 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 remanded, the requirements are still in effect thus requiring the scrubber and SCR projects.

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 installed a wet limestone scrubber at Wateree Station. The Company has incurred capital expenditures totaling approximately $517 million through 2010 for these projects. The EPA has proposed a revised rule which is currently being reviewed by the Company. 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 has collected funds from customers for its storm damage reserve (see Note 2 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 2005 the EPA issued the 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 rule on mercury emissions in 2011 but cannot predict 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 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 NSR.

The 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 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 new cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The EPA has said that it will issue a rule that modifies requirements for existing intake structures by mid March 2011. 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.

The EPA has publicly stated its intention to propose new federal regulations affecting the management and disposal of CCRs, such as ash, in 2011. Such regulations could result in the treatment of some CCRs 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, 2010, the federal government has not accepted any spent fuel from Summer Station Unit 1 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 2017 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1 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:

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 $4.2 million, the estimated remaining liability at December 31, 2010. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

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

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 FERC as to certain acquisitions and other matters.

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 PHMSA 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 is in the process of developing the plan and procedures to ensure that it will be fully compliant with the new law. SCE&G believes that any additional costs incurred to comply with the rule will be recoverable through rates.

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 Act directed the DOT to establish the Integrity Management Rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy's approximately 593 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 63 miles are located within these areas. Through December 2010, PSNC Energy has assessed 98 percent of the pipeline and is required to complete its assessment of the remainder by December 2012. PSNC Energy will be required to reinspect these same miles of pipeline approximately every seven years. PSNC Energy currently estimates the total costs through December

2012 to be $8.1 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 costs incurred to comply with DOT's pipeline integrity management requirements until resolution of PSNC Energy's next general rate proceeding.

CGT has approximately 72 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.

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.

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, in the event 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 2 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 would be necessary and, if they were, 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, 2010, the Company's net investments in fossil/hydro and nuclear generation assets were approximately $2.7 billion and $1.4 billion, respectively.

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 for which they have not yet been billed. 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 $221.1 million at December 31, 2010 and $187.2 million at December 31, 2009, compared to total revenues of $4.6 billion and $4.2 billion for the years 2010 and 2009, respectively.

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 Unit 1, 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 Unit 1. 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.

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 net periodic benefit cost or 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 $23.5 million recorded in 2010 reflects the use of a 5.75% 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 5.50% in 2010 would have increased the Company's pension cost by $1.2 million. Had the assumed long-term rate of return on assets been 8.25%, the Company's pension cost for 2010 would have increased by $1.8 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 2010, 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 2010 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. As of the beginning of 2011, the plan's historical 10, 15, 20 and 25 year

cumulative performance showed actual returns of 4.2%, 8.1%, 9.8% and 10.2%, respectively. For 2011, the expected rate of return is 8.25%.

As noted in Results of Operations, due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, the Company recorded significant amounts of pension cost in 2009 and 2010 compared to the pension income recorded in 2008 and previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed 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 that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring, as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.

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 significant 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 5.90%, derived using a cash flow matching technique, and recorded a net cost of $17.8 million for 2010. Had the selected discount rate been 5.65%, the expense for 2010 would have been $0.4 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.

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, 2010, the Company has recorded an ARO of $117 million for nuclear plant decommissioning (as discussed above) and an ARO of $380 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 may 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 utilities remains in place.

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 approximately $5.5 billion for plant costs and for related transmission infrastructure costs, which costs are projected based on historical one-year and five year escalation rates as required by the SCPSC.

SCE&G's latest Integrated Resource Plan filed with the SCPSC on February 2011, continues to support SCE&G's need for 55% of the output of the two units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has more recently indicated that it will seek to reduce its 45% ownership in the New Units. If Santee Cooper's ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act became law. This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and requires numerous rule-makings by the Commodity Futures Trading Commission and the SEC to implement. The Company is currently complying with these enacted regulations and intends to comply with regulations enacted in the future but cannot predict when the final regulations will be issued or what requirements they will impose.

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 operating leases in the normal course of business, generally for office space, furniture, vehicles, equipment and rail cars.

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

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

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, 2010 Millions of dollars	2011		2012		2013		2014		2015		Thereafter		Total		Fair Value
Long-Term Debt:
Fixed Rate ($)		623.0		268.6		159.8		43.7		7.8		3,196.6		4,299.5		4,666.0
Average Fixed Interest Rate (%)		6.76		6.20		7.02		4.97		5.48		6.07		6.20		—
Variable Rate ($)		4.4		4.4		4.4		4.4		4.4		155.0		177.0		162.7
Average Variable Interest Rate (%)		1.00		1.00		1.00		1.00		1.00		.72		.76		—
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)		303.2		253.2		—		—		—		—		556.4		4.0
Pay Interest Rate (%)		6.02		4.92		—		—		—		—		5.52		—
Receive Interest Rate (%)		6.89		6.28		—		—		—		—		6.62		—
Pay Fixed/Receive Variable ($)		654.4		254.4		4.4		4.4		4.4		155.0		1,077.0		(77.5	)
Average Pay Interest Rate (%)		4.59		4.21		6.17		6.17		6.17		4.84		4.56		—
Average Receive Interest Rate (%)		.31		.31		1.00		1.00		1.00		.68		.37		—

	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		181.4		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		—

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 $21 million at December 31, 2010 and $34 million at December 31, 2009, which amounts do not have a stated interest rate associated with them.

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.

Swaps

Commodity Swaps:
	Pay fixed/receive variable(b)	58.7	20.0	11.8	1.3	1.3
	Average pay rate(a)	5.2148	6.0192	6.0053	5.4025	5.4025
	Average received rate(a)	4.5100	5.0829	5.3345	5.4926	5.6379
	Fair Value(b)	50.7	16.9	10.5	1.3	1.4
	Pay variable/receive fixed(b)	40.2	14.4	7.9	1.3	1.4
	Average pay rate(a)	4.5247	5.0768	5.3336	5.4926	5.6379
	Average received rate(a)	5.1886	5.7475	5.4443	5.4300	5.4300
	Fair Value(b)	46.1	16.3	8.1	1.3	1.3
Basis Swaps:
	Pay variable/receive variable(b)	19.4	9.1	2.6	—	—
	Average pay rate(a)	4.5683	5.1232	5.4273	—	—
	Average received rate(a)	4.5631	5.0946	5.3320	—	—
	Fair Value(b)	19.3	9.1	2.5	—	—

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 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 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 weighted average cost of gas calculations. 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.

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, 2010 and 2009, 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, 2010. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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, 2010, 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, 2011 expressed an unqualified opinion on the Company's internal control over financial reporting.

December 31, (Millions of dollars)			2010			2009

Assets
Utility Plant In Service			$	11,714		$	10,835
Accumulated Depreciation and Amortization				(3,495	)		(3,302	)
Construction Work in Progress				1,081			1,149
Nuclear Fuel, Net of Accumulated Amortization				132			97
Goodwill, Net of Accumulated Amortization and Writedown of $276				230			230

	Utility Plant, Net			9,662			9,009

Nonutility Property and Investments:
	Nonutility property, net of accumulated depreciation of $118 and $107			299			291
	Assets held in trust, net-nuclear decommissioning			76			67
	Other investments			78			73

	Nonutility Property and Investments, Net			453			431

Current Assets:
	Cash and cash equivalents			55			162
	Receivables, net of allowance for uncollectible accounts of $9 and $9			837			694
	Inventories (at average cost):
		Fuel		316			376
		Materials and supplies		125			115
		Emission allowances		6			10
	Prepayments and other			271			164
	Deferred income taxes			21			—

	Total Current Assets			1,631			1,521

Deferred Debits and Other Assets:
	Regulatory assets			1,061			985
	Other			161			148

	Total Deferred Debits and Other Assets			1,222			1,133

Total			$	12,968		$	12,094

December 31, (Millions of dollars)		2010		2009

Capitalization and Liabilities
Common equity		$	3,702	$	3,408
Long-Term Debt, Net			4,152		4,483

Total Capitalization			7,854		7,891

Current Liabilities:
	Short-term borrowings		420		335
	Current portion of long-term debt		337		28
	Accounts payable		526		428
	Customer deposits and customer prepayments		100		103
	Taxes accrued		146		134
	Interest accrued		72		71
	Dividends declared		61		59
	Derivative financial instruments		65		8
	Other		140		90

	Total Current Liabilities		1,867		1,256

Deferred Credits and Other Liabilities:
	Deferred income taxes, net		1,391		1,122
	Deferred investment tax credits		56		111
	Asset retirement obligations		497		477
	Pension and other postretirement benefits		202		229
	Regulatory liabilities		913		879
	Other		188		129

	Total Deferred Credits and Other Liabilities		3,247		2,947

Commitments and Contingencies (Note 10)			—		—

Total		$	12,968	$	12,094

Years Ended December 31, (Millions of dollars, except per share amounts)			2010			2009			2008

Operating Revenues:
	Electric		$	2,367		$	2,141		$	2,236
	Gas-regulated			989			958			1,247
	Gas-nonregulated			1,245			1,138			1,836

		Total Operating Revenues		4,601			4,237			5,319

Operating Expenses:
	Fuel used in electric generation			942			818			864
	Purchased power			17			17			36
	Gas purchased for resale			1,679			1,570			2,547
	Other operation and maintenance			670			640			675
	Depreciation and amortization			335			316			319
	Other taxes			190			177			168

		Total Operating Expenses		3,833			3,538			4,609

Operating Income				768			699			710

Other Income (Expense):
	Other income			51			65			79
	Other expenses			(39	)		(37	)		(42	)
	Interest charges, net of allowance for borrowed funds used during construction of $10, $23 and $16			(266	)		(233	)		(227	)
	Allowance for equity funds used during construction			20			28			14

		Total Other Expense		(234	)		(177	)		(176	)

Income Before Income Tax Expense and Earnings from Equity Method Investments				534			522			534
Income Tax Expense				159			167			189

Income Before Earnings from Equity Method Investments				375			355			345
Earnings from Equity Method Investments				1			2			8

Net Income				376			357			353
Less Preferred Stock Dividends of Subsidiary				—			(9	)		(7	)

Income Available to Common Shareholders of SCANA			$	376		$	348		$	346

Per Common Share Data
		Basic Earnings Per Share of Common Stock	$	2.99		$	2.85		$	2.95
		Diluted Earnings Per Share of Common Stock		2.98			2.85			2.95
Weighted Average Common Shares Outstanding (millions)
		Basic		125.7			122.1			117.0
		Diluted		126.3			122.2			117.1
Dividends Declared Per Share of Common Stock			$	1.90		$	1.88		$	1.84

For the Years Ended December 31, (Millions of dollars)			2010			2009			2008

Cash Flows From Operating Activities:
Net Income			$	376		$	357		$	353
Adjustments to reconcile net income to net cash provided from operating activities:
	Earnings from equity method investments, net of distributions			3			1			2
	Deferred income taxes, net			240			93			76
	Depreciation and amortization			341			329			327
	Amortization of nuclear fuel			36			18			17
	Allowance for equity funds used during construction			(20	)		(28	)		(14	)
	Carrying cost recovery			(3	)		(5	)		(5	)
	Cash provided (used) by changes in certain assets and liabilities:
		Receivables		(143	)		134			(21	)
		Inventories		11			(76	)		(114	)
		Prepayments and other		(109	)		64			(103	)
		Other regulatory assets		(71	)		(82	)		(23	)
		Regulatory liabilities		(13	)		(6	)		(13	)
		Accounts payable		79			(46	)		(14	)
		Taxes accrued		12			6			(28	)
		Interest accrued		1			2			18
	Changes in other assets			(32	)		(36	)		(3	)
	Changes in other liabilities			103			(46	)		(1	)

Net Cash Provided From Operating Activities				811			679			454

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures			(846	)		(787	)		(833	)
	Proceeds from investments and sale of assets			104			31			19
	Nonutility property additions			(30	)		(127	)		(71	)
	Investments			(102	)		(6	)		(2	)

Net Cash Used For Investing Activities				(874	)		(889	)		(887	)

Cash Flows From Financing Activities:
	Proceeds from issuance of common stock			149			191			42
	Proceeds from issuance of debt			259			600			1,526
	Repayments of debt			(300	)		(599	)		(231	)
	Redemption/repurchase of equity securities			—			(113	)		—
	Dividends			(237	)		(234	)		(219	)
	Short-term borrowings, net			85			255			(547	)

Net Cash Provided From (Used For) Financing Activities				(44	)		100			571

Net Increase (Decrease) in Cash and Cash Equivalents				(107	)		(110	)		138
Cash and Cash Equivalents, January 1				162			272			134

Cash and Cash Equivalents, December 31			$	55		$	162		$	272

Supplemental Cash Flow Information:
Cash paid for—Interest (net of capitalized interest of $9, $23 and $16)			$	268		$	233		$	196
—Income taxes				61			79			121
Noncash Investing and Financing Activities:
	Accrued construction expenditures			179			160			92
	Capital lease of gas utility plant			6			—			—

			Common Stock							Accumulated Other Comprehensive Income (Loss)

			Common Stock				Retained Earnings
Millions			Shares		Amount		Retained Earnings						Total
Balance as of January 1, 2008				117	$	1,407	$	1,575		$	(22	)	$	2,960

Comprehensive Income (Loss):
	Income Available to Common Shareholders of SCANA							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							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

Comprehensive Income:
	Income Available to Common Shareholders of SCANA							376						376
	Other Comprehensive Income, net of taxes $5										8			8

		Total Comprehensive Income						376			8			384

Issuance of Common Stock				4		149								149
Dividends Declared on Common Stock								(239	)					(239	)

Balance as of December 31, 2010				127	$	1,789	$	1,960		$	(47	)	$	3,702

SCANA, 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 business 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.

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.

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.

Utility plant is stated substantially at original cost. The costs of additions, replacements 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 and replacements 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 expense.

regulated subsidiaries calculated AFC using average composite rates of 7.4% for 2010, 7.5% for 2009 and 6.3% for 2008. 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.

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:

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 DOE under a contract for disposal of spent nuclear fuel.

SCE&G, operator of Summer Station, and Santee Cooper jointly own Summer Station Unit 1 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 Unit 1 was $1.0 billion as of December 31, 2010 and 2009 (including amounts capitalized related to the recording of AROs). Accumulated depreciation associated with SCE&G's share of Summer Station Unit 1 was $548.8 million and $538.3 million as of December 31, 2010 and 2009, respectively (including amounts capitalized related to the recording of AROs). SCE&G's share of the direct expenses associated with operating Summer Station Unit 1 is included in other operation and maintenance expenses and totaled $94.5 million in 2010, $92.7 million in 2009 and $87.4 million in 2008.

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with Westinghouse and Stone & Webster, Inc. for the design and construction of the New Units at the site of Summer Station. The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units. SCE&G's portion of the construction work in progress for the New Units was $891.2 million at December 31, 2010 and $476.5 million at December 31, 2009. 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 SCPSC.

SCE&G's latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G's need for 55% of the output of the two units. As previously reported, SCE&G has

been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has more recently indicated that it will seek to reduce its 45% ownership in the New Units. If Santee Cooper's ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $77.9 million at December 31, 2010 and $59.4 million at December 31, 2009.

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 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2010, SCE&G incurred $28.6 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 scheduled outage upon completion of the preceding scheduled 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 2009 outage were $32.7 million, of which SCE&G was responsible for $21.8 million. SCE&G is accruing $1.2 million per month for its portion of the outage scheduled for the spring of 2011. As of December 31, 2010, SCE&G had an accrued balance of $14.3 million. There was no accrued balance at December 31, 2009.

The Company considers amounts categorized by FERC as "acquisition adjustments" with carrying values of $210 million for PSNC Energy (Gas Distribution segment) and $20 million for CGT (All Other segment) to be goodwill. The Company tests these goodwill amounts for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is a two-step process which, in step one, requires estimation of the fair value of the respective reporting unit and the comparison of that amount to the carrying value of the reporting unit. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required.

In evaluations of PSNC Energy fair value is estimated using the assistance of either an independent appraisal or from internally prepared cash flow and guideline company analyses using methodologies similar to those used by the appraiser and with certain input data having been provided by the appraiser. In evaluations of CGT, estimated fair value has been obtained from internal analyses. In all evaluations for the periods presented, step one has indicated no impairment, and no impairment

charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense.

SCE&G's two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, 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 Unit 1. 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 2010, 2009 and 2008) 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 for Summer Station Unit 1 on an after-tax basis.

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.

Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At December 31, 2010, such counterparties held 47% of PSNC Energy's natural gas inventory, with a carrying value of $22 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 October 31, 2011.

The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted

tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company's regulated subsidiaries; otherwise, they are charged or credited to income tax expense.

The Company's rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.

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.

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. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. 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. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

In its consolidated statements of income, the Company presents the activities of its regulated and significant nonregulated businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).

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 $221.1 million at December 31, 2010 and $187.2 million at December 31, 2009.

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.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs, including the results of its hedging program, and amounts contained in rates is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy's PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

SCE&G's gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers.

PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average, per customer consumption, whether impacted by weather or other factors.

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.

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.

A reconciliation of the weighted average number of common shares for each of the three years ended December 31, 2010 for basic and diluted purposes is as follows:

On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G's retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC's order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other things, the SCPSC's order (1) included implementation of an eWNA for SCE&G's electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G's customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

In December 2009, SCE&G submitted to the FERC revised tariff sheets to change the network and point to point transmission rates under SCE&G's OATT. The request, if approved, would result in an annual revenue increase of approximately $5.6 million. In compliance with the OATT, on March 1, 2010 pursuant to an order issued by the FERC, SCE&G implemented, subject to refund, the proposed tariff sheets. On May 17, 2010, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or "Annual Update" for the period June 1, 2010 through May 31, 2011. The FERC accepted the tariff sheets in the "Annual Update" and made them effective, subject to refund, as of June 1, 2010.

In January 2010, the SCPSC approved SCE&G's request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of the New 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 May 2009, two intervenors filed separate appeals of the order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC's prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC's decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G's share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court's ruling, however, does not affect the project schedule or disturb the SCPSC's issuance of a certificate of environmental compatibility and public convenience and necessity, which is necessary to construct the new units. On November 15, 2010, SCE&G filed a petition to the SCPSC seeking an order approving an updated capital cost schedule for the construction of the company's new nuclear units that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million. A hearing on this petition is scheduled for April 4, 2011, and the SCPSC is expected to rule on the request in May 2011.

Under the BLRA, 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 September 2009, the SCPSC approved SCE&G's annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.

The 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. On October 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%. The rate adjustment was effective with the first billing cycle of November 2010. 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.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G's gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G's gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.

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 addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

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 liabilities which are summarized in the following tables. Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	December 31,

Millions of dollars	2010		2009
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	173
Under-collections—electric fuel adjustment clause		25		55
Environmental remediation costs		32		26
AROs and related funding		298		279
Franchise agreements		45		50
Deferred employee benefit plan costs		326		325
Planned major maintenance		6		5
Deferred losses on interest rate derivatives		83		50
Other		36		22

Total Regulatory Assets	$	1,061	$	985

Regulatory Liabilities:
Accumulated deferred income taxes	$	26	$	30
Other asset removal costs		780		733
Storm damage reserve		38		44
Monetization of bankruptcy claim		37		40
Deferred gains on interest rate derivatives		26		29
Other		6		3

Total Regulatory Liabilities	$	913	$	879

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

Under-collections—electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates during the period January 2012 through April 2012. SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assets are expected to be recovered over periods of up to approximately 23 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs. These regulatory assets

are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 95 years.

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.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become longer at the election of the SCPSC.

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 pursuant to specific SCPSC orders. SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate swaps, treasury rate locks and forward starting swap agreements designated as cash flow hedges. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.

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

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 and vegetation management expenditures in excess of amounts included in base rates. During the 12 months ended December 31, 2010 and 2009, SCE&G applied costs of $9.5 million and $10.0 million, respectively, to the reserve. Pursuant to SCPSC's July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely pending future SCPSC action.

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

The SCPSC or the NCUC (collectively, state public service commission) or 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 public service 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. The costs are currently not 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.

The Company's articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCANA's junior subordinated indenture (relating to the Hybrids), SCE&G's bond indenture (relating to the Bonds) and PSNC Energy's note purchase and debenture purchase agreements 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.

Cash dividends on SCANA's common stock were declared during 2010, 2009 and 2008 at an annual rate per share of $1.90, $1.88 and $1.84, respectively.

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

The Company recognized losses of $12.3 million, $66.9 million and $14.3 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2010, 2009 and 2008, respectively.

Authorized shares of common stock were 150 million as of December 31, 2010 and 2009.

On January 7, 2009, SCANA sold 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. SCANA issued common stock valued at $91.1 million (when issued) during each of the years ended December 31, 2010 and 2009, which was satisfied using original issue shares, through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan.

SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010 and entered into forward sale agreements for the sale of approximately 6.6 million shares to be settled no later than February 29, 2012. There have been no shares yet issued under the forward sales agreements. SCANA intends to use any net proceeds it receives upon settlement of the forward

sale agreements to finance capital expenditures, including the construction of the New Units, and for general corporate purposes, including repayment of indebtedness incurred for such purposes. Upon physical settlement of the forward sale agreements, SCANA will deliver shares of its common stock in exchange for cash proceeds at the forward sale price (which is the public offering price less the underwriting discount and is subject to adjustment as provided in the forward sale agreements); however, subject to certain exceptions, SCANA may elect cash or net share settlement for all or a portion of its obligations under the forward sale agreements. Assuming physical settlement of the forward sale agreements based upon an adjusted forward price of approximately $32.30 per share as of December 31, 2011, SCANA would receive net proceeds of approximately $213.9 million upon settlement.

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

			2010						2009

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		106			6.47	%		110			6.47	%
First Mortgage Bonds (secured)		2011 - 2039		2,560			6.03	%		2,560			6.03	%
Junior Subordinated Notes (unsecured)(c)		2065		150			7.70	%		150			7.70	%
GENCO Notes (secured)		2011 - 2024		262			5.91	%		272			5.93	%
Industrial and Pollution Control Bonds(d)		2012 - 2038		228			4.63	%		228			4.63	%
Senior Debentures(e)		2012 - 2026		206			6.94	%		110			7.35	%
Borrowings Under Credit Agreements				—			—			100			.50	%
Fair Value of Interest Rate Swaps(f)				5						8
Other		2011 - 2027		36						38

Total debt				4,503						4,526
Current maturities of long-term debt				(337	)					(28	)
Unamortized discount				(14	)					(15	)

Total long-term debt, net			$	4,152					$	4,483

The annual amounts of long-term debt maturities for the years 2011 through 2015 are summarized as follows:

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire $150 million medium term notes due February 15, 2011. In January 2011, SCE&G issued $250 million of 5.45% first mortgage bonds maturing on February 1, 2041. Proceeds from the sale were used to retire $150 million First Mortgage Bonds due February 1, 2011 and for general corporate purposes. The borrowings refinanced by these 2011 issuances are classified within Long-term Debt, Net in the consolidated balance sheet.

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

On October 25, 2010, SCANA, SCE&G (including Fuel Company) and PSNC Energy entered into Five-Year Credit Agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company and $100 million, respectively, which are scheduled to expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each

company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. 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 SCANA, SCE&G (including Fuel Company) and PSNC Energy.

In December 2008, JEDA issued $35.0 million of Industrial Revenue Bonds, 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, and a first mortgage bond issued in favor of the bond trustee. 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.

Total income tax expense attributable to income for 2010, 2009 and 2008 is as follows:

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	2010			2009			2008

Income	$	377		$	348		$	346
Income tax expense		159			167			189
Preferred stock dividends		—			9			7

Total pre-tax income	$	536		$	524		$	542

Income taxes on above at statutory federal income tax rate	$	188		$	183		$	190
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		9			14			17
Amortization of state investment tax credits (less federal income tax effect)		(18	)		(6	)		(2	)
Allowance for equity funds used during construction		(8	)		(10	)		(5	)
Deductible dividends—Stock Purchase Savings Plan		(9	)		(8	)		(7	)
Amortization of federal investment tax credits		(3	)		(3	)		(3	)
Domestic production activities deduction		—			(4	)		(1	)
Other differences, net		—			1			—

Total income tax expense	$	159		$	167		$	189

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $1.4 billion at December 31, 2010 and $1.1 billion at December 31, 2009 are as follows:

Millions of dollars	2010		2009

Deferred tax assets:
Nondeductible reserves	$	103	$	99
Nuclear decommissioning		45		42
Financial instruments		22		11
Unamortized investment tax credits		41		54
Deferred compensation		25		24
Unbilled revenue		19		16
Monetization of bankruptcy claim		14		15
Other		11		3

Total deferred tax assets		280		264

Deferred tax liabilities:
Property, plant and equipment		1,418		1,169
Pension plan income		23		2
Deferred employee benefit plan costs		106		113
Deferred fuel costs		42		42
Other		61		61

Total deferred tax liabilities		1,650		1,387

Net deferred tax liability	$	1,370	$	1,123

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 IRS has completed examinations of the Company's federal returns through 2004, and the Company's federal returns through 2006 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 2007.

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, the Company revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.

In connection with the change in method of accounting for certain repair costs referred to above, the Company identified approximately $36 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. By December 31, 2011, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.

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 2010, 2009 or 2008.

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 as a component of other comprehensive income (loss) or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, 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.

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 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 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, 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 or liability for the over- or under-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.

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

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.

The Company was party to natural gas derivative contracts outstanding in the following quantities:

The Company was party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $556.4 million and $559.6 million at December 31, 2010 and 2009, respectively, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $1,077.0 million and $181.4 million, respectively.

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
Millions of dollars		Balance Sheet Location(c)	Fair Value		Balance Sheet Location(c)	Fair Value
As of December 31, 2010
Derivatives designated as hedging instruments
	Interest rate contracts	Other current assets	$	1	Other current liabilities	$	57
		Other deferred debits		7	Other deferred credits		25
	Commodity contracts	Other current liabilities		1	Other current liabilities		5
					Other deferred credits		2

Total			$	9		$	89

As of December 31, 2009
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

As of December 31, 2010
Derivatives not designated as hedging instruments
	Commodity contracts	Prepayments and other	$	3
	Energy management contracts	Prepayments and other		7	Prepayments and other	$	1
		Other deferred debits		2	Other current liabilities		6
					Other deferred credits		2

Total			$	12		$	9

As of December 31, 2009
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

The effect of derivative instruments on the statement of income for the year ended December 31, 2010 is as follows:

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 deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $11.5 million and $6.6 million for the years ended December 31, 2010 and 2009, respectively.

As of December 31, 2010, 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 $2.0 million, net of tax as an increase to gas cost and approximately $3.1 million, net of tax as an increase to interest expense, assuming natural gas and financial markets remain at their

current levels. As of December 31, 2010, all of the Company's commodity cash flow hedges settle by their terms before the end of 2015.

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in 2010 and $1.2 million, net of tax, in 2009. These amounts are recorded within interest expense on the statement of income.

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, 2010 and 2009, the Company has posted $20.0 million and $17.9 million, respectively, 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, 2010 and 2009, the Company would be required to post an additional $74.0 million and $6.3 million, respectively, 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, 2010 and 2009, are $94.0 million and $24.2 million, respectively.

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 hierarchy in which the measurements fall, were as follows:

There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition, there were no transfers of fair value amounts into or out of Levels 1 and 2 during any period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2010 and December 31, 2009 were as follows:

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 discounted cash flow models with independently sourced data. Early settlement of long-term debt may not be possible or may not be considered prudent.

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

The Company sponsors a noncontributory defined benefit pension plan covering substantially all regular, full-time 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 certain active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.

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

The accumulated benefit obligation for retirement benefits was $766.0 million at the end of 2010 and $747.2 million at the end of 2009. 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:

An 8.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. 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 December 31, 2010 by $1.8 million and December 31, 2009 by $1.9 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 2010 by $1.6 million and December 31, 2009 by $1.7 million.

Amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2010 and 2009 were as follows:

In connection with the joint ownership of Summer Station, as of December 31, 2010 and 2009, the Company recorded within deferred debits $13.0 million and $11.2 million, respectively, attributable to Santee Cooper's portion of shared pension costs. As of December 31, 2010 and 2009, the Company also recorded within deferred debits $10.7 million and $10.2 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.

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, 2010 and 2009 and the target allocation for 2011 are as follows:

For 2011, the expected long-term rate of return on assets will be 8.25%. 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.

Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At

December 31, 2010 and 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

Millions of dollars			Quoted Market Prices in Active Market for Identical Assets/Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)
December 31, 2010
Common stock	$	363	$	363
Mutual funds		206		25	$	181
Short-term investment vehicles		18				18
US Treasury securities		51				51
Corporate debt securities		51				51
Loans secured by mortgages		9				9
Municipals		3				3
Common collective trusts		45				45
Limited partnerships		26		1		25
Multi-strategy hedge funds		45					$	45

	$	817	$	389	$	383	$	45

December 31, 2009
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
Municipals		2				2
Common collective trusts		166				166
Multi-strategy hedge funds		14					$	14

	$	759	$	351	$	394	$	14

The Pension 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. Other mutual funds, common collective trusts and limited partnerships 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 spreads or benchmarked thereto. Corporate debt securities and municipals 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 this multi-strategy hedge fund 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.

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:

The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and the Company does not anticipate making significant contributions to the pension plan until after 2011.

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.

In February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of increased pension cost by deferring as a regulatory asset the amount of pension cost above that which was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.

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

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

The estimated amounts to be amortized from accumulated other comprehensive income into net periodic benefit cost in 2011 are as follows:

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 approximately $100,000.

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 2010, 2009 and 2008 were $20.8 million, $21.0 million and $20.5 million, respectively. These matching contributions were made in the form of SCANA common stock.

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.

The 2008-2010 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. 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, and were subject to forfeiture in the event of retirement or termination of employment prior to the end of the cycle, subject to exceptions for death, disability or change in control. The remaining 80% of the award was made in performance shares. 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 TSR as compared to a peer group of utilities (weighted 50%) and growth in "GAAP-adjusted net earnings per share from operations" (weighted 50%). Accordingly, payouts under the 2008-2010 performance 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 2011.

In the 2009-2011 and 2010-2012 performance cycles, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash, and are subject to forfeiture in the event of retirement or termination of employment prior to the end of the cycle, subject to exceptions for death, disability or change in control. 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 $12.1 million in 2010, $9.1 million in 2009, and $2.6 million in 2008.

Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $14.2 million in 2010, $7.2 million in 2009 and $17.2 million in 2008. Fair value adjustments resulted in capitalized compensation costs of $2.4 million in 2010, $0.9 million in 2009 and $1.9 million in 2008.

A summary of activity related to nonvested shares granted in 2008, as discussed above follows:

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 2010 and 2009 and $0.8 million in 2008 and recognized related tax benefits of $0.3 million in each of 2010, 2009 and 2008. The Company capitalized compensation costs of $0.1 million in each of 2010, 2009 and 2008. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized.

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, 2010, all outstanding options were currently exercisable at prices ranging from $27.10-$27.52, and had a weighted-average remaining contractual life of 1.0 year.

The exercise of stock options during 2010 and 2009 was satisfied using original issue shares, and during 2008 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, 2010, 2009 and 2008, cash realized upon the exercise of options and related tax benefits were not significant.

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 Unit 1, 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 Unit 1) 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 prospective 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 Unit 1 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.

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 installed a wet limestone scrubber at Wateree Station. The EPA has proposed a revised rule which is currently being evaluated by the Company. 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 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 in 2011 but cannot predict what requirements it will impose.

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 expects to recover them through rates.

other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of $4.2 million, which reflects its estimated remaining liability at December 31, 2010. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually 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 plaintiffs alleged 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 and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment but did not assert a specific dollar amount for the claims. In June 2007, the Circuit Court issued a ruling that limits the plaintiffs' 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 remained limited to easements in Charleston County. In July 2008, the plaintiffs' motion to add SCI to the lawsuit as an additional defendant was granted. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been tentatively settled as to all easements and rights-of-ways currently containing fiber optic communication lines in South Carolina. The parties are proceeding to identify class members and resolve other settlement related issues. While this settlement is subject to a fairness hearing before it is finally approved, SCE&G and SCI currently know of no reason why such approval will not be given. This tentative settlement will not have a material adverse impact on the Company's 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.

The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $13.9 million in 2010, $23.7 million in 2009 and $13.5 million in 2008. Future minimum rental payments under such leases are as follows:

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 $1.9 billion in 2010, $1.7 billion in 2009 and $2.8 billion in 2008. Future payments under such purchase commitments are as follows:

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

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, 2010, the maximum future payments (undiscounted) that the Company could be required to make under guarantees totaled $1.4 billion.

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, 2010, the Company has recorded an ARO of approximately $117 million for nuclear plant decommissioning (see Note 1) and an ARO of approximately $380 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:

The Company received cash distributions from equity-method investees of $4.8 million in 2010, $3.3 million in 2009 and $6.2 million in 2008. The Company made investments in equity-method investees of $5.1 million in 2010, $1.6 million in 2009 and $2.2 million in 2008.

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. The Company made cash investments in these affiliated companies of $2.2 million in 2008.

SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, both involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G's receivables and payables from these affiliates were insignificant at December 31, 2010. SCE&G accounts for these investments using the equity method. SCE&G's total purchases were $97.3 million in 2010 and insignificant in 2009. SCE&G's total sales were $96.9 million in 2010 and insignificant in 2009.

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.

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. One of these subsidiaries operates a FERC-regulated interstate pipeline company and the other 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 marketing segments differ from each other in their respective markets and customer type.

	Electric Operations			Gas Distribution		Retail Gas Marketing		Energy Marketing		All Other			Adjustments/ Eliminations			Consolidated Total

2010
External Revenue	$	2,367		$	979	$	553	$	692	$	37		$	(27	)	$	4,601
Intersegment Revenue		7			1		—		182		410			(600	)		—
Operating Income		554			140		n/a		n/a		19			55			768
Interest Expense		22			24		1		—		3			216			266
Depreciation and Amortization		263			63		4		—		29			(24	)		335
Income Tax Expense		(1	)		28		19		2		10			101			159
Income Available to Common Shareholders		n/a			n/a		31		4		(6	)		347			376
Segment Assets		7,882			2,161		196		116		1,322			1,291			12,968
Expenditures for Assets		752			107		—		—		41			(24	)		876
Deferred Tax Assets		5			11		9		5		18			(27	)		21
2009
External Revenue	$	2,141		$	948	$	522	$	616	$	37		$	(27	)	$	4,237
Intersegment Revenue		8			1		—		161		416			(586	)		—
Operating Income		504			132		n/a		n/a		19			44			699
Interest Expense		15			21		—		—		4			193			233
Depreciation and Amortization		244			61		4		—		28			(21	)		316
Income Tax Expense		—			28		15		2		9			113			167
Income Available to Common Shareholders		n/a			n/a		24		3		(12	)		333			348
Segment Assets		7,312			2,040		183		99		1,205			1,255			12,094
Expenditures for Assets		817			76		—		1		130			(110	)		914
Deferred Tax Assets		—			10		8		6		19			(43	)		—
2008
External Revenue	$	2,236		$	1,237	$	632	$	1,205	$	45		$	(36	)	$	5,319
Intersegment Revenue		12			1		—		279		408			(700	)		—
Operating Income		523			120		n/a		n/a		16			51			710
Interest Expense		15			23		1		—		5			183			227
Depreciation and Amortization		254			57		2		—		23			(17	)		319
Income Tax Expense		3			25		20		1		8			132			189
Income Available to Common Shareholders		n/a			n/a		33		2		(6	)		317			346
Segment Assets		6,602			2,074		201		139		1,291			1,195			11,502
Expenditures for Assets		859			146		—		3		83			(187	)		904
Deferred Tax Assets		4			7		7		23		20			(38	)		23

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 and regulated segments. Revenues from non-reportable and nonregulated 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.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual

2010 Millions of dollars, except per share amounts
Total operating revenues	$	1,428	$	939	$	1,088	$	1,146	$	4,601
Operating income		230		137		196		205		768
Income available to common shareholders		127		54		101		94		376
Basic earnings per share		1.02		.43		.80		.74		2.99
Diluted earnings per share		1.02		.43		.79		.74		2.98
2009 Millions of dollars, except per share amounts
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 earnings per share		.94		.45		.84		.62		2.85
Diluted earnings per share		.94		.45		.84		.62		2.85

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

South Carolina Electric & Gas Company (SCE&G, together with its consolidated affiliates, Consolidated SCE&G) is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, and transportation 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 approximately 22,600 square miles.

During 2010, the lingering effects of an economic recession showed modest signs of improvement in the southeast. At December 31, 2010 a preliminary estimate of seasonally adjusted unemployment for South Carolina was 10.7%. Though improved from December 2009, this rate remains stubbornly high and indicates that economic recovery in South Carolina lags the nation. Customer growth was slightly positive in 2010, though customer usage continued to decline. Consolidated SCE&G expects customer growth to be similar and usage patterns to continue in 2011.

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.

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 latest Integrated Resource Plan filed with the SCPSC in February 2011, continues to support SCE&G's need for 55% of the output of the two units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has more recently indicated that it will seek to reduce its 45% ownership in the New Units. If Santee Cooper's ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

beyond what was proposed and included in the original BLRA filing. The revised schedule does not change the previously announced completion date for the New Units or the originally announced cost.

Consolidated SCE&G expects that significant federal legislative initiatives related to energy will be hampered through 2012 due to each chamber of Congress being controlled by different political parties. Significant regulatory initiatives by the EPA and other federal agencies, however, will likely proceed. These initiatives may require SCE&G to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). 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. Consolidated SCE&G cannot predict whether such initiatives 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 CCR, such as ash. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

The gas distribution segment is comprised of the local distribution operations of SCE&G and is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of South Carolina. At December 31, 2010 this segment provided natural gas to approximately 313,500 customers in areas covering 22,600 square miles.

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. One effect of the recent economic recession was an overall decrease in demand for natural gas which, coupled with discoveries of shale gas in the United States, resulted in significantly lower prices for this commodity in 2009 and 2010.


• 2010 vs 2009		Net income increased $72.7 million due to higher electric margin and $6.5 million due to higher gas margin. These increases were partially offset by increased generation, transmission and distribution expenses of $10.4 million, by increased incentive compensation of $5.6 million, by increased interest expense of $14.2 million, by lower equity AFC of $8.8 million, by higher property taxes of $7.5 million and by $12.9 million due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in 2009. In late 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.
• 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 SCE&G in 2009, $3.0 million due to higher gas margin, $3.1 million due to decreased incentive compensation and $4.6 million due to decreased generation, transmission and distribution expenses. These increases 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.

Pension cost (income) was recorded on Consolidated SCE&G's income statements and balance sheets as follows:

In connection with the SCPSC's July 2010 electric rate order, SCE&G began deferring all pension expense related to retail electric operations as a regulatory asset. These amounts will be deferred until such time as future rate recovery is provided for by the SCPSC. From January 2009 until the July 2010 order, SCE&G was allowed by the SCPSC to mitigate a significant portion of pension cost by deferring as a regulatory asset the amount of pension expense above the level of pension income which was included in rates. This pension cost arose due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets. SCE&G had recorded significant pension income in 2008.

No contribution to the pension trust was necessary, nor did limitations on benefit payments apply, in or for any period reported.

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. Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 6.6% of income before income taxes in 2010, 11.5% in 2009 and 6.3% in 2008, respectively.

Consolidated SCE&G's Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2010 and 2009:

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


• 2010 vs 2009		Margin increased by $37.0 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $30.7 million due to an increase in base rates approved by the SCPSC under the BLRA. In addition, margin increased by $54.2 million (net of eWNA after its implementation) due to weather, by $5.8 million due to higher transmission revenue and off-system sales and by $13.6 million due to the adoption of SCPSC-approved lower electric depreciation rates in 2009, the effect of which was offset by a reduction in the recovery of fuel costs (electric revenue). During the first quarter of 2010, SCE&G deferred $25 million of incremental revenue as a result of the abnormally cold weather in its service territory (see Note 2 to the consolidated financial statements). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G's annual fuel cost proceeding. (See also discussion at "Income Taxes".) Finally, pursuant to the SCPSC-approved retail electric base rate order in 2010, SCE&G adopted an eWNA thereby mitigating the effects of abnormal weather on its margins.
• 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.

Sales volumes (in MWh) related to the electric margin above, by class, were as follows:

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

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

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

Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year. Other interest expense increased in 2010 primarily due to higher principal balances on short-term debt over the prior year. In 2009 other interest expense decreased primarily due to lower principal balances on short-term debt over the prior year.

Income tax expense (and the effective tax rate) decreased in 2010 primarily due to the recognition of certain previously deferred state income tax credits pursuant to both the settlement of a fuel cost proceeding in the first quarter of 2010 and the retail electric base rate increase in July 2010. (See Note 5 to the consolidated financial statements for reconciling differences between income tax expense and statutory tax expense.) Income tax expense decreased in 2009 primarily due to the resolution of the contested EIZ Credits in favor of SCE&G (see discussion above at Other Income (Expense)) and changes in operating income.

Consolidated SCE&G 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. Consolidated SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. Consolidated SCE&G's ratio of earnings to fixed charges for the year ended December 31, 2010 was 3.18.

Consolidated SCE&G's cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of Consolidated SCE&G 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. Consolidated 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 Consolidated SCE&G continues its ongoing construction program, Consolidated SCE&G expects to seek increases in rates. Consolidated SCE&G's future financial position and results of operations will be affected by Consolidated SCE&G's ability to obtain adequate and timely rate and other regulatory relief.

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $771 million in 2010 and are estimated to be $1.0 billion in 2011.

Consolidated SCE&G's current estimates of its capital expenditures for construction and nuclear fuel for 2011-2013, which are subject to continuing review and adjustment, are as follows:

Consolidated SCE&G's contractual cash obligations as of December 31, 2010 are summarized as follows:

Included in the table above in purchase obligations is SCE&G's portion of a contractual agreement for the design and construction of the New Units at the Summer Station site. SCE&G expects to be a joint owner and share operating costs and generation output of the New Units, with SCE&G accounting for 55 percent of the cost and output and other joint owner(s) 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, 2010, obligations arising from these contracts are included in the purchase obligations within the Contractual Cash Obligations table above.

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 10 to the consolidated financial statements.

SCE&G also has a legal obligation associated with the decommissioning and dismantling of Summer Station Unit 1 and other conditional asset retirement obligations that are not listed in the contractual cash obligations above. See Notes 1 and 10 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 significant contributions are anticipated until after 2011. SCE&G's cash payments under the health care and life insurance benefit plan were $9.3 million in 2010, and such annual payments are expected to increase up to $11.0 million in the future.

Consolidated SCE&G'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 Consolidated SCE&G 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 $1.2 billion of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $150 million of short-term indebtedness. The authority to make such issuances will expire in October 2012.

On October 25, 2010, SCE&G (including Fuel Company) entered into Five-Year Credit Agreements in the amounts of $1.1 billion, of which $400 million relates to Fuel Company, which are scheduled to expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 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 to SCE&G (including Fuel Company).

At December 31, 2010 and 2009, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

As of December 31, 2010, Consolidated SCE&G had not borrowed from its $1.1 billion facilities, had approximately $381 million in commercial paper borrowings outstanding, was obligated under $.3 million in LOC-supported letters of credit, and had approximately $28 million in cash and temporary investments. Consolidated SCE&G 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. Average short-term borrowings outstanding during 2010 were approximately $279 million. Short-term cash needs were met through a variety of methods in the first part of 2010, including issuance of commercial paper and draws against credit facilities. By year end, all short-term needs were being met with commercial paper due to more favorable interest rates and market liquidity.

At December 31, 2010, Consolidated SCE&G had net available liquidity of approximately $747 million, and its revolving credit facilities are in place until October 2015. Consolidated SCE&G's long-term debt portfolio has a weighted average maturity of over 17 years and bears an average cost of 6.26%. Most long-term debt, other than facility draws, effectively bears fixed interest rates or is swapped to fixed. To further preserve liquidity, Consolidated SCE&G 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, all of which is beneficially owned by SCANA.

In January 2011, SCE&G issued $250 million of 5.45% first mortgage bonds maturing on February 1, 2041. Proceeds from the sale were used to retire $150 million of SCE&G's First Mortgage Bonds due February 1, 2011 and for general corporate purposes.

During 2010 Consolidated SCE&G experienced net cash outflows related to financing activities of $40 million primarily due to the repayment of long-term debt and payment of dividends, partially offset by contribution from parent and issuance of short-term and long-term debt.

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

Consolidated SCE&G'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 CAA, the CAIR, the CWA, the Nuclear Waste Act and the 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, 2010, Consolidated SCE&G's capital expenditures for environmental control equipment at its fossil fuel generating stations totaled $373.9 million. In addition, Consolidated SCE&G made expenditures to operate and maintain environmental control equipment at its fossil plants of $6.5 million during 2010, $5.6 million during 2009, and $5.8 million during 2008, which are included in "Other operation and maintenance" expense and made expenditures to handle waste ash of $5.9 million in 2010, $6.5 million in 2009, and $4.9 million in 2008, which are included in "Fuel used in electric generation." In addition, included within "Other operation and maintenance" expense is annual amortization of $1.4 million in each of 2010, 2009, and 2008 related to SCE&G's recovery of MGP remediation costs as approved by the SCPSC. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for Consolidated SCE&G are $14.5 million for 2011 and $113.3 million for the four-year period 2011-2015. These expenditures are included in Consolidated SCE&G's Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.

At the state level, no significant environmental legislation that would affect Consolidated SCE&G's operations advanced during 2010. Consolidated SCE&G cannot predict whether such legislation will be introduced or enacted in 2011, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.

With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, Consolidated SCE&G is 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. Consolidated SCE&G cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact Consolidated SCE&G, and the following discussion should not be considered all-inclusive.

From a regulatory perspective, Consolidated SCE&G continually monitors and evaluates current and projected emission levels and strives to comply with all state and federal regulations regarding those emissions. Consolidated SCE&G participates in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also has constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G has announced plans to construct the New Units 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 remanded, the requirements are still in effect thus requiring the scrubber and SCR projects.

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, Consolidated SCE&G 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 installed a wet limestone scrubber at Wateree Station. Consolidated SCE&G has to incurred capital expenditures totaling approximately $517 million through 2010 for these projects. The EPA has proposed a revised rule which is currently being reviewed by Consolidated SCE&G. 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.

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 has collected funds from customers for its storm damage reserve (see Note 2 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 Consolidated SCE&G to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.

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 Consolidated SCE&G will be affected by the initiative in the future. Consolidated SCE&G believes that any enforcement action relative to its compliance with the CAA would be without merit. Consolidated SCE&G further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with NSR.

The 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 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 new cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The EPA has said that it will issue a rule that modifies requirements for existing intake structures by mid March 2011. Consolidated SCE&G 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 Consolidated SCE&G. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

The EPA has publicly stated its intention to propose new federal regulations affecting the management and disposal of CCRs, such as ash, in 2011. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

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. Consolidated SCE&G 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 Consolidated SCE&G 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. Consolidated SCE&G has assessed the following matters:

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

The RSA 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 PHMSA 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 is in the process of developing the plan and procedures to ensure that it will be fully compliant with the new law. SCE&G believes that any additional cost incurred to comply with the rule will be recoverable through rates.

Following are descriptions of Consolidated SCE&G's accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.

Consolidated SCE&G'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, in the event of deregulation or other changes in the regulatory environment, Consolidated SCE&G 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 Consolidated

SCE&G's Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. See Note 2 to the consolidated financial statements for a description of Consolidated SCE&G's regulatory assets and liabilities, including those associated with Consolidated SCE&G's environmental assessment program.

Consolidated SCE&G'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, Consolidated SCE&G could be required to write down its investment in those assets. Consolidated SCE&G cannot predict whether any write-downs would be necessary and, if they were, the extent to which they would adversely affect Consolidated SCE&G's results of operations in the period in which they would be recorded. As of December 31, 2010, Consolidated SCE&G's net investments in fossil/hydro and nuclear generation assets were $2.7 billion and $1.4 billion, respectively.

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, SCE&G 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 for which they have not yet been billed. 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, 2010 and 2009, accounts receivable included unbilled revenues of $123.4 million and $104.3 million, respectively, compared to total revenues of $2.8 billion and $2.6 billion for the years 2010 and 2009, respectively.

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 SCE&G'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).

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 net periodic benefit cost or 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 $23.5 million ($18.9 million attributable to SCE&G) recorded in 2010 reflects the use of a 5.75% 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 5.50% in 2010 would have increased SCANA's pension cost by $1.2 million. Had the assumed long-term rate of return on assets been 8.25%, SCANA's pension cost for 2010 would have increased by $1.8 million.

As noted in Results of Operations, due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, SCE&G recorded significant amounts of pension cost in 2009 and 2010 compared to the pension income recorded in 2008 and previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed 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 that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.

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 5.90%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $13.2 million for 2010. Had the selected discount rate been 5.65%, the expense for 2010 would have been $0.3 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.

Consolidated SCE&G 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 Consolidated SCE&G's regulated utility operations, their recording has no significant impact on results of operations. As of December 31, 2010, Consolidated SCE&G has recorded AROs of $117 million for nuclear plant decommissioning (as discussed above) and $361 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 may 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 utilities remains in place.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act became law. This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and requires numerous rule-makings by the Commodity Futures Trading Commission and the SEC to implement. Consolidated SCE&G is currently complying with these enacted regulations and intends to comply with regulations in the future but cannot predict when the final regulations will be issued or what requirements they will impose.

Consolidated SCE&G does not hold significant investments in unconsolidated special purpose entities. Consolidated 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, vehicles, equipment and rail cars, none of which are considered significant.

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

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

The tables below provide information about long-term debt issued by Consolidated 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. For interest rate swaps, the figures shown reflect notional amounts, weighted average 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.

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 $21 million at December 31, 2010 and $30 million at December 31, 2009, which amounts do not have stated interest rates associated with them.

The following table provides information about SCE&G'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.

SCE&G 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.

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 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 weighted average cost of gas calculations. The offset to the change in fair value of these derivatives is deferred.

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, 2010 and 2009, 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, 2010. 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 the Company as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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.

December 31, (Millions of dollars)			2010			2009

Assets
Utility Plant In Service:			$	10,112		$	9,286
Accumulated Depreciation and Amortization				(3,098	)		(2,926	)
Construction Work in Progress				1,051			1,138
Nuclear Fuel, Net of Accumulated Amortization				133			97

	Utility Plant, Net ($634 related to VIEs at December 31, 2010)			8,198			7,595

Nonutility Property and Investments:
	Nonutility property, net of accumulated depreciation			46			42
	Assets held in trust, net-nuclear decommissioning			76			67
	Other investments			4			2

	Nonutility Property and Investments, Net			126			111

Current Assets:
	Cash and cash equivalents			31			134
	Receivables, net of allowance for uncollectible accounts of $3 and $3			507			397
	Receivables-affiliated companies			—			41
	Inventories (at average cost):
		Fuel		216			259
		Materials and supplies		117			107
		Emission allowances		6			10
	Prepayments and other			168			89
	Deferred income taxes			15			—

	Total Current Assets ($221 related to VIEs at December 31, 2010)			1,060			1,037

Deferred Debits and Other Assets:
	Pension asset			57			—
	Regulatory assets			996			936
	Other			137			134

	Total Deferred Debits and Other Assets ($43 related to VIEs at December 31, 2010)			1,190			1,070

Total			$	10,574		$	9,813

December 31, (Millions of dollars)			2010		2009

Capitalization and Liabilities
Common equity			$	3,437	$	3,162
Noncontrolling interest				104		97

		Total Equity		3,541		3,259
Long-Term Debt, net				3,037		3,158

Total Capitalization				6,578		6,417

Current Liabilities:
	Short-term borrowings			381		254
	Current portion of long-term debt			22		18
	Accounts payable			341		250
	Affiliated payables			140		144
	Customer deposits and customer prepayments			60		51
	Taxes accrued			137		128
	Interest accrued			50		51
	Dividends declared			54		50
	Derivative liabilities			34		—
	Other			80		43

	Total Current Liabilities			1,299		989

Deferred Credits and Other Liabilities:
	Deferred income taxes, net			1,240		972
	Deferred investment tax credits			56		111
	Asset retirement obligations			478		458
	Pension and other postretirement benefits			163		168
	Regulatory liabilities			662		639
	Other			98		59

	Total Deferred Credits and Other Liabilities			2,697		2,407

Commitments and Contingencies (Note 10)				—		—

Total			$	10,574	$	9,813

For the Years Ended December 31, (Millions of dollars)			2010			2009			2008

Operating Revenues:
	Electric		$	2,374		$	2,149		$	2,248
	Gas			441			420			568

		Total Operating Revenues		2,815			2,569			2,816

Operating Expenses:
	Fuel used in electric generation			947			822			866
	Purchased power			17			17			36
	Gas purchased for resale			287			276			429
	Other operation and maintenance			514			490			506
	Depreciation and amortization			271			255			265
	Other taxes			175			162			155

		Total Operating Expenses		2,211			2,022			2,257

Operating Income				604			547			559

Other Income (Expense):
	Other income			12			28			36
	Other expenses			(13	)		(11	)		(16	)
	Interest charges, net of allowance for borrowed funds used during construction of $10, $22 and $15			(186	)		(164	)		(155	)
	Allowance for equity funds used during construction			19			28			13

	Total Other Expense			(168	)		(119	)		(122	)

Income Before Income Tax Expense, Earnings (Losses) from Equity Method Investments and Preferred Stock Dividends				436			428			437
Income Tax Expense				130			140			158

Income Before Earnings (Losses) from Equity Method Investments				306			288			279
Earnings (Losses) from Equity Method Investments				(2	)		—			3

Net Income				304			288			282
Less Net Income Attributable to Noncontrolling Interest				14			7			9

Net Income Attributable to SCE&G				290			281			273
Preferred Stock Cash Dividends Declared				—			(9	)		(7	)

Earnings Available to Common Shareholder			$	290		$	272		$	266

Dividends Declared on Common Stock			$	199		$	179		$	165

For the Years Ended December 31, (Millions of dollars)				2010			2009			2008

Cash Flows From Operating Activities:
	Net income			$	304		$	288		$	282
	Adjustments to reconcile net income to net cash provided from operating activities:
		Losses (earnings) from equity method investments, net of distributions			2			—			(3	)
		Deferred income taxes, net			234			74			99
		Depreciation and amortization			276			266			265
		Amortization of nuclear fuel			36			18			17
		Allowance for equity funds used during construction			(19	)		(28	)		(13	)
		Carrying cost recovery			(3	)		(5	)		(5	)
		Cash provided (used) by changes in certain assets and liabilities:
			Receivables		(110	)		91			(9	)
			Inventories		(5	)		(144	)		(76	)
			Prepayments		(87	)		43			(23	)
			Regulatory assets		(55	)		(84	)		(25	)
			Other regulatory liabilities		(11	)		(2	)		(7	)
			Accounts payable		59			(1	)		13
			Taxes accrued		9			8			4
			Interest accrued		(1	)		1			17
		Changes in other assets			(78	)		(35	)		4
		Changes in other liabilities			120			(54	)		(110	)

Net Cash Provided From Operating Activities					671			436			430

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures				(766	)		(745	)		(739	)
	Nonutility property additions				(5	)		(6	)		(8	)
	Proceeds from investments and sales of assets				49			27			8
	Investment in affiliate				41			(23	)		(18	)
	Investments				(43	)		(6	)		(2	)

Net Cash Used For Investing Activities					(724	)		(753	)		(759	)

Cash Flows From Financing Activities:
	Proceeds from issuance of debt				90			421			1,109
	Contribution from parent				146			348			15
	Repayment of debt				(219	)		(423	)		(13	)
	Redemption of preferred stock				—			(113	)		—
	Dividends				(195	)		(182	)		(164	)
	Short-term borrowings—affiliate, net				1			61			(110	)
	Short-term borrowings, net				127			220			(430	)

Net Cash Provided From (Used For) Financing Activities					(50	)		332			407

Net Increase (Decrease) in Cash and Cash Equivalents					(103	)		15			78
Cash and Cash Equivalents, January 1					134			119			41

Cash and Cash Equivalents, December 31				$	31		$	134		$	119

Supplemental Cash Flow Information:
Cash paid for—Interest (net of capitalized interest of $9, $22 and $15)				$	175		$	152		$	119
—Income taxes					31			61			51
Noncash Investing and Financing Activities:
	Accrued construction expenditures				168			141			74

		Common Stock							Accumulated Other Comprehensive Income (Loss)

		Common Stock				Retained Earnings						Noncontrolling Interest			Total Equity
Millions		Shares		Amount		Retained Earnings						Noncontrolling Interest			Total Equity
Balance at January 1, 2008			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:
Earnings Available for Common Shareholder							272						7			279
Deferred Cost of Employee Benefit Plans, net of tax $8										13						13

Total Comprehensive Income							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

Comprehensive Income:
Earnings Available for Common Shareholder							290						14			304
Deferred Cost of Employee Benefit Plans, net of tax $19										31						31

Total Comprehensive Income							290			31			14			335
	Capital Contributions From Parent				146											146
	Cash Dividends Declared						(192	)					(7	)		(199	)

Balance at December 31, 2010			40	$	1,934	$	1,505		$	(2	)	$	104		$	3,541

SCE&G (together with its consolidated affiliates, Consolidated SCE&G), a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA Corporation (SCANA), a South Carolina corporation. Consolidated SCE&G 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, Fuel Company and 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 (which are considered to be VIEs), 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, SCE&G's parent. Accordingly, GENCO's and Fuel Company's equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G's condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 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 4.

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. Consolidated SCE&G calculated AFC using average composite rates of 7.3% for 2010, 7.4% for 2009 and 6.0% for 2008. 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.

Consolidated SCE&G 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 2.84% in 2010, 2.95% in 2009 and 3.15% in 2008.

Consolidated 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 DOE under a contract for disposal of spent nuclear fuel.

Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New

Units. These amounts totaled $77.9 million at December 31, 2010 and $59.4 million at December 31, 2009.

Under SCE&G's method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2010, 2009 and 2008) are invested in insurance policies on the lives of certain SCE&G and affiliate 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 for Summer Station Unit 1 on an after-tax basis.

Consolidated SCE&G 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.

Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below.

These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.

Consolidated SCE&G 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 Consolidated SCE&G, in the form of capital contributions. Consolidated SCE&G received capital contributions under such provisions of $5.8 million in 2010 and $8.7 million in 2009.

Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.

Consolidated SCE&G 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.

SCE&G 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. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. 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. Environmental expenditures that related to an existing condition caused by past operations and that have no future economic benefit are expensed.

In its consolidated statements of income, Consolidated SCE&G presents the activities of its regulated businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).

Consolidated SCE&G 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 $123.4 million at December 31, 2010 and $104.3 million at December 31, 2009.

Customers subject to the PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is deferred and included when making the next adjustment to the cost of gas factor. In addition, included in these deferred amounts are realized gains and losses incurred in SCE&G's natural gas hedging program.

Effective for the year beginning January 1, 2010, Consolidated SCE&G adopted accounting guidance that requires an enterprise to perform an analysis to determine whether it has a controlling financial interest in a VIE. The adoption of this guidance did not significantly impact Consolidated SCE&G's results of operations, cash flows or financial position.

2010 until May 2011. SCE&G is allowed to charge and recover carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period. In February 2011, SCE&G filed for an increase to the cost of fuel component of its rates to be effective with the first billing cycle of May 2011. The increase is subject to approval by the SCPSC. The hearing on this matter has been scheduled for March 24, 2011.

On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G's retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC's order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other things, the SCPSC's order (1) included implementation of an eWNA for SCE&G's electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G's customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including 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's order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the DMS rate rider tariff sheet with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings before the SCPSC regarding the DSM programs, net lost revenues, program costs, incentive and net program benefits.

In January 2010, the SCPSC approved SCE&G's request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of the New 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.

proceedings so long as the construction proceeds in accordance with schedules, estimates and projections 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 September 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009.

In May 2009, two intervenors filed separate appeals of the order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC's prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC's decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G's share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court's ruling, however, does not affect the project schedule or disturb the SCPSC's issuance of a certificate of environmental compatibility and public convenience and necessity, which is necessary to construct the new units. On November 15, 2010, SCE&G filed a petition to the SCPSC seeking an order approving an updated capital cost schedule for the construction of the company's new nuclear units that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million. A hearing on this petition is scheduled for April 4, 2011, and the SCPSC is expected to rule on the request in May 2011.

Under the BLRA, 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 September 2009, the SCPSC approved SCE&G's annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G's gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G's gas purchasing policies and procedures was conducted on November 10, 2010, before the SCPSC. The SCPSC issued an order in December 2010

finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.

Consolidated SCE&G's 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, Consolidated SCE&G has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Substantially all of its regulatory assets are either explicitly excluded from rate base or are effectly excluded from rate base due to their being offset by related liabilities.

	December 31,

Millions of dollars	2010		2009
Regulatory Assets:
Accumulated deferred income taxes	$	205	$	167
Under-collections—electric fuel adjustment clause		25		55
Environmental remediation costs		27		19
AROs and related funding		284		265
Franchise agreements		45		50
Deferred employee benefit plan costs		288		306
Planned major maintenance		6		5
Deferred losses on interest rate derivatives		83		50
Other		33		19

Total Regulatory Assets	$	996	$	936

Regulatory Liabilities:
Accumulated deferred income taxes	$	26	$	29
Other asset removal costs		568		535
Storm damage reserve		38		44
Deferred gains on interest rate derivatives		26		29
Other		4		2

Total Regulatory Liabilities	$	662	$	639

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

Under-collections—electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates during the period January 2012 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 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.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs.

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 pursuant to specific SCPSC orders. SCE&G collected $8.5 million annually through July 15, 2010, through electric rates to offset turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

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

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 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 SCE&G. The costs are currently not 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, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

Authorized shares of SCE&G common stock were 50 million as of December 31, 2010 and 2009.

SCE&G's 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, 2010, $58 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

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

The annual amounts of long-term debt maturities for the years 2011 through 2015 are summarized as follows:

In January 2011, SCE&G issued $250 million of 5.45% first mortgage bonds maturing on February 1, 2041. Proceeds from the sale were used to retire $150 million First Mortgage Bonds due February 1, 2011 and for general corporate purposes. The borrowing refinanced by this issuance is classified within Long-term Debt, Net in the consolidated balance sheet.

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

revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 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 to SCE&G (including Fuel Company).

In December 2008, JEDA issued $35.0 million of Industrial Revenue, 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, and a first mortgage bond issued in favor of the bond trustee. 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. 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 and a guarantee by SCANA in favor of the bond trustee. This letter of credit expires on November 9, 2011.

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

Total income tax expense attributable to income for 2010, 2009 and 2008 is as follows:

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	2010			2009			2008

Net income	$	290		$	281		$	273
Income tax expense		130			140			158
Noncontrolling interest		14			7			9

Total pre-tax income	$	434		$	428		$	440

Income taxes on above at statutory federal income tax rate	$	152		$	150		$	154
Increases (decreases) attributed to:
Allowance for equity funds used during construction		(8	)		(10	)		(5	)
State income taxes (less federal income tax effect)		6			11			14
State investment tax credits (less federal income tax effect)		(18	)		(6	)		(2	)
Amortization of federal investment tax credits		(3	)		(3	)		(3	)
Domestic production activities deduction		—			(4	)		(1	)
Other differences, net		1			2			1

Total income tax expense	$	130		$	140		$	158

The tax effects of significant temporary differences comprising Consolidated SCE&G's net deferred tax liability of $1.2 billion at December 31, 2010 and $979 million at December 31, 2009 are as follows:

Millions of dollars	2010		2009

Deferred tax assets:
Nondeductible reserves	$	85	$	82
Nuclear decommissioning		45		42
Unamortized investment tax credits		40		53
Deferred compensation		8		9
Unbilled revenue		19		15
Other		5		1

Total deferred tax assets		202		202

Deferred tax liabilities:
Property, plant and equipment		1,205		977
Pension plan income		45		12
Deferred employee benefit plan costs		91		106
Deferred fuel costs		42		42
Other		44		44

Total deferred tax liabilities		1,427		1,181

Net deferred tax liability	$	1,225	$	979

Consolidated SCE&G is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns. The IRS has completed examinations of SCANA's federal returns through 2004, and SCANA's federal returns through 2006 are closed for

additional assessment. With few exceptions, Consolidated SCE&G is no longer subject to state and local income tax examinations by tax authorities for years before 2007.

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, SCE&G revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.

In connection with the change in method of accounting for certain repair costs referred to above, Consolidated SCE&G identified approximately $36 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. By December 31, 2011, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Consolidated SCE&G has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2010, 2009 and 2008.

Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, 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 Consolidated SCE&G. 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 Consolidated SCE&G. The Risk Management Committee, which is comprised of certain officers, including the Consolidated SCE&G'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.

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. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.

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, 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 for accounting purposes.

Consolidated SCE&G uses interest rate swaps to manage interest rate risk on certain debt issuances and to synthetically convert variable rate debt to fixed rate debt. In addition, in anticipation of the issuance of debt, Consolidated SCE&G 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.

SCE&G was party to natural gas derivative contracts for 2,460,000 DT and 2,365,000 DT at December 31, 2010 and 2009, respectively. Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $421.4 million and $71.4 million at December 31, 2010 and 2009, respectively.

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
Millions of dollars		Balance Sheet Location(a)	Fair Value		Balance Sheet Location(a)	Fair Value
As of December 31, 2010
Derivatives designated as hedging instruments
	Interest rate contracts	Other deferred debits	$	4	Other current liabilities	$	34
					Other deferred credits		1

Total			$	4		$	35

Derivatives not designated as hedging instruments
	Commodity contracts	Prepayments and other	$	1
As of December 31, 2009
Derivatives designated as hedging instruments
	Interest rate contracts	Other deferred debits	$	4	Other deferred credits	$	1
Derivatives not designated as hedging instruments
	Commodity contracts	Prepayments and other	$	1

Other gains (losses) recognized in income representing interest rate hedge ineffectiveness were insignificant in 2010 and $1.2 million, net of tax, in 2009. These amounts are recorded within interest expense on the statement of income.

Certain of Consolidated SCE&G's derivative instruments contain contingent provisions that require collateral to be provided upon the occurrence of specific events, primarily credit downgrades. As of December 31, 2010 and 2009, Consolidated SCE&G 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, 2010 and 2009, Consolidated SCE&G would be required to post an additional $34.9 million and $43,258, respectively, 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, 2010 and 2009, are $34.9 million and $43,258, respectively.

SCE&G 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. Consolidated SCE&G'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 hierarchy in which the measurements fall, were as follows:

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2010 and December 31, 2009 were as follows:

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

SCE&G participates in SCANA's noncontributory defined benefit pension plan, which covers substantially all regular, full-time 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, SCE&G participates in SCANA's unfunded postretirement health care and life insurance programs which provide benefits to certain 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.

The accumulated benefit obligation for retirement benefits was $649.0 million at the end of 2010 and $631.6 million at the end of 2009. 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:

A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at December 31, 2010 by $1.4 million and December 31, 2009 by $1.5 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 2010 by $1.3 million and December 31, 2009 by $1.4 million.

Amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2010 and 2009 were as follows:

In connection with the joint ownership of Summer Station, as of December 31, 2010 and 2009, SCE&G recorded within deferred debits $13.0 million and $11.2 million, respectively, attributable to Santee Cooper's portion of shared pension costs. As of December 31, 2010 and 2009, SCE&G also recorded within deferred debits $10.7 million and $10.2 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.

The pension plan asset allocation at December 31, 2010 and 2009 and the target allocation for 2011 are as follows:

December 31, 2010 and 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

Millions of dollars	December 31, 2010		Quoted Market Prices in Active Market for Identical Assets/Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)
December 31, 2010
Common stock	$	331	$	331
Mutual funds		187		22	$	165
Short-term investment vehicles		17				17
US Treasury securities		47				47
Corporate debt securities		46				46
Loans secured by mortgages		8				8
Municipals		3				3
Common collective trusts		41				41
Limited partnerships		24		1		23
Multi-strategy hedge funds		41					$	41

	$	745	$	354	$	350	$	41

December 31, 2009
Common stock	$	286	$	286
Mutual funds		60		19	$	41
Short-term investment vehicles		32				32
US Treasury securities		60				60
Corporate debt securities		56				56
Loans secured by mortgages		8				8
Municipals		2				2
Common collective trusts		145				145
Multi-strategy hedge funds		12					$	12

	$	661	$	305	$	344	$	12

exchanges and do not trade on a daily basis. The valuation of this multi-strategy hedge fund 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.

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

The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and SCE&G does not anticipate making significant contributions to the pension plan until after 2011.

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

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

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

The estimated amounts to be amortized from accumulated other comprehensive income into net periodic benefit cost in 2011 are as follows:

SCE&G participates in a SCANA-sponsored defined contribution plan in 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. SCE&G provides 100% matching contributions up to 6% of an employee's eligible earnings. Total matching contributions made to the plan for 2010, 2009 and 2008 were $16.6 million, $16.6 million and $16.1 million, respectively. These matching contributions were made in the form of SCANA common stock.

SCE&G participates in 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.

against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in "GAAP-adjusted net earnings per share from operations" (weighted 50%). Accordingly, payouts under the 2008-2010 performance 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 2011.

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 $2.4 million in 2010, $1.7 million in 2009 and $0.4 million in 2008 were paid.

Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $9.0 million in 2010, $4.5 million in 2009 and $10.7 million in 2008. Fair value adjustments resulted in capitalized compensation costs of $2.2 million in 2010, $0.9 million in 2009 and $1.8 million in 2008.

A summary of activity related to nonvested shares granted in 2008 as discussed above follows:

Nonvested shares were granted at a price corresponding to the opening price of SCANA common stock on the date of the grant. SCE&G expensed compensation costs for nonvested shares of $0.1 million in each of 2010, 2009 and 2008. Tax benefits and capitalized compensation costs in each of 2010, 2009 and 2008 were not significant. All of the shares were vested at December 31, 2010.

The exercise of stock options during 2010 and 2009 was satisfied using original issue shares, and during 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, 2010, 2009 and 2008, cash realized upon the exercise of options and related tax benefits were not significant.

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 Unit 1 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 Consolidated SCE&G's results of operations, cash flows and financial position.

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 May 13, 2010, the EPA finalized the GHG Tailoring Rule, which sets thresholds for GHG emissions that define when permits under the New Source Review, the Prevention of Significant Deterioration, and the Title V Operation Permits programs are required for new and existing facilities (such as SCE&G's and GENCO's generating facilities). Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

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 installed a wet limestone scrubber at Wateree Station. The EPA has proposed a revised rule which is currently being evaluated by Consolidated SCE&G. 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 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. Consolidated SCE&G expects the EPA will issue a new rule on mercury emissions in 2011 but cannot predict what requirements it will impose.

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually 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 plaintiffs alleged 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 and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment but did not assert a specific dollar amount for the claims. In June 2007, the Circuit Court issued a ruling that limits the plaintiffs' 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 remained limited to easements in Charleston County. In July 2008, the plaintiffs' motion to add SCI to the lawsuit as an additional defendant was granted. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been tentatively settled as to all easements and rights-of-ways currently containing fiber optic communication lines in South Carolina. The parties are proceeding to identify class members and resolve other settlement related issues. While this settlement is subject to a fairness hearing before it is finally approved, SCE&G and SCI currently know of no reason why such approval will not be given. This tentative settlement will not have a material adverse impact on Consolidated SCE&G's results of operations, cash flows or financial condition.

Consolidated SCE&G 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 Consolidated SCE&G's results of operations, cash flows or financial condition.

Consolidated SCE&G is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $9.3 million in 2010, $16.5 million in 2009 and $12.7 million in 2008. Future minimum rental payments under such leases are as follows:

Consolidated SCE&G 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 $859.7 million in 2010, $756.9 million in 2009 and $949.8 million in 2008. Future payments under such purchase commitments are as follows:

Consolidated SCE&G 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 Consolidated SCE&G's regulated utility operations. As of December 31, 2010, Consolidated SCE&G has recorded an ARO of approximately $117 million for nuclear plant decommissioning (see Note 1) and an ARO of approximately $361 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:

CGT transports natural gas to SCE&G to supply certain electric generation requirements and to serve retail gas customers. SCE&G had approximately $2.1 million and $2.8 million payable to CGT for transportation services at December 31, 2010 and December 31, 2009, respectively.

SCE&G purchases natural gas and related pipeline capacity from SEMI to supply its Jasper County Electric Generating Station, Urquhart Electric Generation Station and to serve its retail gas customers. Such purchases totaled approximately $182.5 million in 2010, $160.8 million in 2009 and $290.5 million in 2008. SCE&G's payables to SEMI for such purposes were $16.1 million and $13.3 million as of December 31, 2010 and 2009, respectively.

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 credits program at the end of 2007, and they were dissolved in 2008. SCE&G made cash investments in these affiliated companies of $2.2 million in 2008 and $16.2 million in 2007.

SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, both involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for these investments using the equity method. SCE&G's receivables and payables from these affiliates were insignificant at December 31, 2010. SCE&G's total purchases were $97.3 million in 2010 and insignificant in 2009. SCE&G's total sales were $96.9 million in 2010 and insignificant in 2009.

Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G's interest income and expense from money pool transactions was not significant for any period presented. At December 31, 2010 and 2009, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $71.0 million and $29.2 million, respectively.

An affiliate processes and pays invoices for Consolidated SCE&G and is reimbursed by them. Consolidated SCE&G owed $39.8 million and $47.1 million to the affiliate at December 31, 2010 and 2009, respectively, for invoices paid by the affiliate on behalf of Consolidated SCE&G.

Consolidated SCE&G's reportable segments are listed in the following table. Consolidated SCE&G uses operating income to measure profitability for its regulated operations. Therefore, earnings available to common shareholders are not allocated to the Electric Operations and gas segments. Intersegment revenues were not significant.

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.

	Electric Operations		Gas Distribution		Adjustments/ Eliminations			Consolidated Total

2010
External Revenue	$	2,374	$	441	$	—		$	2,815
Operating Income (Loss)		554		52		(2	)		604
Interest Expense		22		—		164			186
Depreciation and Amortization		263		22		(14	)		271
Segment Assets		7,882		590		2,102			10,574
Expenditures for Assets		752		39		(20	)		771
Deferred Tax Assets		5		n/a		10			15
2009
External 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
External 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

Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments. As a result, Consolidated SCE&G 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. Consolidated SCE&G'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 amounts 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.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As of December 31, 2010, an evaluation was performed under the supervision and with the participation of SCANA's management, including the CEO and 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, 2010. There has been no change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2010 that has materially affected or is reasonably likely to materially affect SCANA's 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, 2010, the effectiveness of such structure and procedures. This management report follows.

The management of 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 CEO and 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, 2010. 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, 2010, internal control over financial reporting is effective based on those criteria.

SCANA's independent registered public accounting firm has issued an attestation report on SCANA's internal control over financial reporting. This report follows.

ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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, 2010, based on 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, 2010, 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, 2010 of the Company and our report dated March 1, 2011 expressed an unqualified opinion on those financial statements and financial statement schedule.

As of December 31, 2010, an evaluation was performed under the supervision and with the participation of SCE&G's management, including the CEO and CFO, of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G's management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that SCE&G's disclosure controls and procedures were effective as of December 31, 2010. There has been no change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2010 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting.

The management of 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 CEO and CFO, to provide reasonable assurance to SCE&G's management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

SCE&G's management assessed the effectiveness of SCE&G's internal control over financial reporting as of December 31, 2010. 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, 2010, 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.

A list of SCANA's executive officers is in Part I of this annual report at page 31. 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 2011 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.

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," "2010 GRANTS OF PLAN-BASED AWARDS," "OUTSTANDING EQUITY AWARDS AT 2010 FISCAL YEAR-END," "2010 OPTION EXERCISES AND STOCK VESTED," "PENSION BENEFITS," "2010 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 2011 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 2011 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, 2010 are summarized as follows:

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 2011 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.

SCANA: The information required by Item 14 is incorporated herein by reference to "PROPOSAL 4—APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM" in SCANA's definitive proxy statement for the 2011 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.

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.

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, 2010 and 2009 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

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.

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 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.

			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
2010	$	9	$	28	$	—	$	28	$	9
2009		11		17		—		19		9
2008		10		14		—		13		11
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2010	$	7	$	1	$	—	$	3	$	5
2009		6		4		—		3		7
2008		7		3		—		4		6
SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2010	$	3	$	6	$	—	$	6	$	3
2009		3		6		—		6		3
2008		2		5		—		4		3
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2010	$	5	$	1	$	—	$	2	$	4
2009		5		3		—		3		5
2008		6		3		—		4		5

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.

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.

		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 as Exhibit 4.03 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	4.04	X		Junior Subordinated Indenture dated as of November 1, 2009 between SCANA Corporation and U.S. Bank National Association, as Trustee (Filed as Exhibit 4.04 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	4.05	X		First Supplemental Indenture to Junior Subordinated Indenture referred to in Exhibit 4.04 dated as of November 1, 2009 (Filed as Exhibit 4.05 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	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)

		Applicable to Form 10-K of

Exhibit No.		SCANA	SCE&G	Description
	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 as Exhibit 10.02 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	*10.03	X	X	SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) (Filed as Exhibit 10.03 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	*10.04	X	X	SCANA Director Compensation and Deferral Plan (including amendments through December 31, 2009) (Filed as Exhibit 10.04 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	*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 as Exhibit 10.07 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	*10.08	X	X	SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) (Filed as Exhibit 10.08 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

			Applicable to Form 10-K of

Exhibit No.			SCANA	SCE&G	Description
	*10.09		X	X	SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) (Filed as Exhibit 10.09 to Form 10-K for the year ended December 31, 2010 and incorporated by reference herein)

	*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)

	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)

	101. INS	**	X		XBRL Instance Document

	101. SCH	**	X		XBRL Taxonomy Extension Schema


ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2010
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.

1-8809	SCANA Corporation (a South Carolina corporation) 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

Title of each class		Registrant

Common Stock, without par value		SCANA Corporation
2009 Series A 7.70% Enhanced Junior Subordinated Notes		SCANA Corporation

Title of each class		Registrant

Series A Nonvoting Preferred Shares		South Carolina Electric & Gas Company


SCANA Corporation	Large accelerated filer ý Smaller reporting company o	Accelerated filer o	Non-accelerated filer o (Do not check if a smaller reporting company)
South Carolina Electric & Gas Company	Large accelerated filer o Smaller reporting company o	Accelerated filer o	Non-accelerated filer ý (Do not check if a smaller reporting company)

Registrant	Description of Common Stock

SCANA Corporation	Without Par Value	127,875,625
South Carolina Electric & Gas Company	Without Par Value	40,296,147	(a)



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		3
DEFINITIONS		5
PART I
Item 1.	Business	7
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	26
Item 3.	Legal Proceedings	28
Item 4.	Reserved	30
Executive Officers of SCANA Corporation		31
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	33
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	34
	South Carolina Electric & Gas Company	110
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	174
Item 9A.	Controls and Procedures	174
Item 9B.	Other Information	177
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	178
Item 11.	Executive Compensation	178
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	178
Item 13.	Certain Relationships and Related Transactions, and Director Independence	179
Item 14.	Principal Accounting Fees and Services	179
PART IV
Item 15.	Exhibits, Financial Statement Schedules	180
SIGNATURES		182
Exhibit Index		184

	Sales						Margins

Customer Classification	2009			2010			2009			2010
Residential		43	%		43	%		49	%		50	%
Commercial		32	%		32	%		33	%		33	%
Industrial		16	%		17	%		13	%		13	%
Sales for resale		6	%		6	%		2	%		2	%
Other		2	%		2	%		2	%		2	%

Total Territorial		99	%		100	%		99	%		100	%
NMST		1	%		—	%		1	%		—	%

Total		100	%		100	%		100	%		100	%

	% of Total MWh Generated

	Actual									Estimated
	2008			2009			2010			2011			2012			2013
Coal		65	%		51	%		52	%		49	%		45	%		47	%
Nuclear		18	%		18	%		21	%		21	%		20	%		23	%
Hydro		4	%		4	%		4	%		3	%		3	%		3	%
Natural Gas & Oil		13	%		27	%		23	%		26	%		31	%		26	%
Biomass		—			—			—			1	%		1	%		1	%

Total		100	%		100	%		100	%		100	%		100	%		100	%

Project		Project

Saluda (Lake Murray)	2011	Stevens Creek	2025
Fairfield Pumped Storage/Parr Shoals	2020	Neal Shoals	2036

	2010								2009

	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
High	$	41.97	$	40.82	$	39.99	$	38.17	$	38.64	$	36.39	$	32.70	$	36.89
Low	$	40.03	$	35.23	$	34.73	$	34.23	$	33.59	$	31.68	$	28.21	$	26.01

Declaration Date	Amount		Declaration Date	Amount

February 19, 2009	$	41.5 million	February 11, 2010	$	45.0 million
April 23, 2009		41.6 million	May 6, 2010		46.0 million
July 30, 2009		44.0 million	July 29, 2010		49.0 million
October 28, 2009		48.0 million	October 27, 2010		52.4 million



Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		35
		Overview	35
		Results of Operations	40
		Liquidity and Capital Resources	46
		Environmental Matters	51
		Regulatory Matters	55
		Critical Accounting Policies and Estimates	56
		Other Matters	58
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		60
Item 8.	Financial Statements and Supplementary Data		63
		Report of Independent Registered Public Accounting Firm	63
		Consolidated Balance Sheets	64
		Consolidated Statements of Income	66
		Consolidated Statements of Cash Flows	67
		Consolidated Statements of Changes in Common Equity and Comprehensive Income	68
		Notes to Consolidated Financial Statements	69



% of Revenues
Regulated	73	%	73	%	65	%
Nonregulated	27	%	27	%	35	%
% of Income Available to Common Shareholders
Regulated	96	%	96	%	94	%
Nonregulated	4	%	4	%	6	%
% of Assets
Regulated	95	%	94	%	93	%
Nonregulated	5	%	6	%	7	%

Millions of dollars		2010			2009			2008

Income Statement Impact:
	Increase (reduction) in employee benefit costs	$	1.1		$	—		$	(0.6	)
	Other income		(3.9	)		(3.7	)		(14.6	)
Balance Sheet Impact:
	Increase (reduction) in capital expenditures		6.0			9.8			(0.3	)
	Component of amount receivable from (payable to) Summer Station Unit 1 co-owner		1.7			2.7			(0.3	)
	Increase in regulatory asset		18.6			31.2			—

Total Pension Cost (Income)		$	23.5		$	40.0		$	(15.8	)

	Cost of Fuel Used

	2008		2009		2010
Per million British thermal units (MMBTU):
Nuclear	$	.45	$	.48	$	.72
Coal		3.21		4.36		4.49
Gas		10.92		4.61		5.48
All Fuels (weighted average)		3.50		3.61		3.80
Per Ton:
Coal	$	79.26	$	108.39	$	110.63
Per thousand cubic feet (MCF):
Gas	$	11.38	$	4.81	$	5.64

	SCANA						SCE&G

Customer Classification	2009			2010			2009			2010
Residential		56.3	%		56.1	%		46.4	%		45.7	%
Commercial		28.3	%		27.2	%		30.3	%		28.8	%
Industrial		10.2	%		11.6	%		19.3	%		22.0	%
Transportation Gas		5.2	%		5.1	%		4.0	%		3.5	%

Total		100.0	%		100.0	%		100.0	%		100.0	%

Millions of dollars	2010				2009				2008

Operating revenues	$	2,367.0	10.6	%	$	2,140.9	(4.3	)%	$	2,236.4
Less: Fuel used in generation		941.5	15.2	%		817.6	(5.3	)%		863.6
Purchased power		17.0	1.2	%		16.8	(53.5	)%		36.1

Margin	$	1,408.5	7.8	%	$	1,306.5	(2.3	)%	$	1,336.7

Classification (in thousands)

Residential		8,791	11.4	%	7,893	0.8	%	7,828
Commercial		7,684	4.5	%	7,350	(1.3	)%	7,450
Industrial		5,863	10.1	%	5,324	(13.5	)%	6,152
Sales for resale (excluding interchange)		1,912	5.3	%	1,815	(1.9	)%	1,850
Other		581	3.4	%	562	(1.2	)%	569

Total territorial		24,831	8.2	%	22,944	(3.8	)%	23,849
Negotiated Market Sales Tariff (NMST)		53	(66.9	)%	160	(63.2	)%	435

	Total	24,884	7.7	%	23,104	(4.9	)%	24,284


• 2010 vs 2009		Territorial sales volumes increased by 1,209 MWh due to weather and by 539 MWh due to higher industrial sales volumes. NMST volumes decreased due to market pricing conditions.
• 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.

Millions of dollars		2010				2009				2008

Operating revenues		$	979.4	3.3	%	$	948.4	(23.4	)%	$	1,238.1
Less: Gas purchased for resale			601.7	2.8	%		585.1	(34.0	)%		886.1

	Margin	$	377.7	4.0	%	$	363.3	3.2	%	$	352.0


• 2010 vs 2009		Margin at SCE&G increased by $9.2 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009 and $3.3 million due to increased customer usage. These increases were partially offset by a decrease of $2.2 million due to an SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. Margin at PSNC Energy increased by $4.0 million primarily due to residential customer growth and improved industrial usage.


• 2009 vs 2008		Margin increased by $2.7 million due to an SCPSC-approved increase in retail gas base rates at SCE&G which became effective with the first billing cycle of November 2008 and by $3.7 million due to an SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009, both of which were offset by a decrease of $3.0 million due to lower 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.

Classification (in thousands)

Residential		45,251	16.0	%	38,995	4.0	%	37,507
Commercial		28,972	6.4	%	27,220	(2.8	)%	28,004
Industrial		18,860	12.3	%	16,798	(13.2	)%	19,345
Transportation gas		33,089	7.3	%	30,845	(2.7	)%	31,698

	Total	126,172	10.8	%	113,858	(2.3	)%	116,554


• 2010 vs 2009		Residential sales volume increased primarily due to customer growth and weather. Commercial and industrial sales volume increased primarily as a result of improved economic conditions.
• 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.

Millions	2010				2009				2008

Operating revenues	$	552.9	6.0	%	$	521.7	(17.4	)%	$	631.7
Income available to common shareholders	$	30.5	27.1	%	$	24.0	(26.2	)%	$	32.5
Delivered volumes (DT)		40.2	15.9	%		34.7	(2.5	)%		35.6


• 2010 vs 2009		Operating revenues increased as a result of colder than normal weather and higher consumption. Income available to common shareholders increased due to higher margins, partially offset by higher bad debt and operating expenses. Delivered volumes increased primarily as a result of colder than normal weather.
• 2009 vs 2008		Operating revenues decreased as a result of lower average retail prices and volumes. Income available to common shareholders decreased due to lower margin, partially offset by lower bad debt expense and the costs of a 2008 GPSC settlement related to operation of pricing plans. Delivered volumes decreased primarily as a result of fewer customers.

Millions	2010				2009				2008

Operating revenues	$	874.1	12.5	%	$	776.9	(47.6	)%	$	1,483.8
Income available to common shareholders	$	3.9	14.7	%	$	3.4	78.9	%	$	1.9
Delivered volumes (DT)		172.8	6.1	%		162.9	6.7	%		152.7


• 2010 vs 2009		Operating revenues increased due to higher sales volume. Income available to common shareholders increased due to lower operating expenses, partially offset by higher bad debt expense. Delivered volumes increased primarily as a result of increased power generation sales.
• 2009 vs 2008		Operating revenues decreased primarily due to lower market prices. Income available to common shareholders increased due to lower operating expenses, including bad debts. Delivered volumes increased primarily as a result of increased power generation sales.

Millions of dollars	2010				2009				2008

Other operation and maintenance	$	669.9	4.7	%	$	639.7	(5.2	)%	$	674.6
Depreciation and amortization		335.1	6.0	%		316.0	(1.0	)%		319.3
Other taxes		190.4	7.6	%		176.9	5.3	%		168.0

Millions of dollars	2010					2009					2008

Other income	$	51.6		(20.0	)%	$	64.5		(17.9	)%	$	78.6
Other expenses		(39.5	)	7.0	%		(36.9	)	(11.1	)%		(41.5	)

Total	$	12.1		(56.2	)%	$	27.6		(25.6	)%	$	37.1


• 2010 vs 2009		Total other income (expense) decreased $13.4 million due to decreased interest income. (See discussion under "Resolution of EIZ Credits" below.)
• 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 Credits" below.)

Millions of dollars	2010				2009				2008

Interest on long-term debt, net	$	261.1	14.3	%	$	228.5	7.7	%	$	212.1
Other interest expense		4.5	(10.0	)%		5.0	(67.1	)%		15.2

Total	$	265.6	13.7	%	$	233.5	2.7	%	$	227.3

Millions of dollars		2011		2012		2013

SCE&G:
Electric Plant:
	Generation (including GENCO)	$	566	$	959	$	908
	Transmission		53		70		68
	Distribution		156		167		173
	Other		37		27		16
	Nuclear Fuel		81		57		106
Gas			50		51		52
Common and other			18		16		17

Total SCE&G			961		1,347		1,340
Other Companies Combined			98		93		107

Total		$	1,059	$	1,440	$	1,447

	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	$	9,068	$	1,303	$	1,133	$	426	$	6,206
Capital leases		12		4		6		2		—
Operating leases		63		12		22		1		28
Purchase obligations		5,785		1,000		2,127		1,398		1,260
Other commercial commitments		5,208		1,062		1,895		977		1,274

Total	$	20,136	$	3,381	$	5,183	$	2,804	$	8,768

				Options

	Futures Contracts			Purchased Call		Purchased Put		Sold Call		Sold Put
	Long			(Long)		(Short)		(Short)		(Long)
2011
Settlement Price(a)		4.51	Strike Price(a)		5.62		4.39		6.90		4.39
Contract Amount(b)		26.4	Contract Amount(b)		56.5		0.5		0.7		0.5
Fair Value(b)		25.1	Fair Value(b)		2.4		—		—		—
2012
Settlement Price(a)		5.11	Strike Price(a)		5.48		—		—		—
Contract Amount(b)		1.6	Contract Amount(b)		4.0		—		—		—
Fair Value(b)		1.6	Fair Value(b)		0.4		—		—		—

Regulated businesses		Nonregulated businesses

South Carolina Electric & Gas Company (SCE&G)		SCANA Energy Marketing, Inc. (SEMI)
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. SCANA Services, Inc.
Carolina Gas Transmission Corporation (CGT)		SCANA Corporate Security Services, Inc.
		Westex Holdings, LLC



SCE&G	2.83	%	2.97	%	3.18	%
GENCO	2.66	%	2.66	%	2.66	%
CGT	1.94	%	1.94	%	1.92	%
PSNC Energy	3.11	%	3.10	%	3.06	%
Aggregate of Above	2.85	%	2.95	%	3.11	%

In Millions

Weighted Average Shares Outstanding—Basic	125.7	122.1	117.0
Net effect of dilutive stock-based compensation plans and equity forward contracts	0.6	0.1	0.1

Weighted Average Shares Outstanding—Diluted	126.3	122.2	117.1