UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2005
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-8809	SCANA Corporation (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	57-0784499
1-3375	South Carolina Electric & Gas Company (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	57-0248695
1-11429	Public Service Company of North Carolina, Incorporated (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	56-2128483

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

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

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

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

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

South Carolina Electric & Gas Company o Public Service Company of North Carolina, Incorporated o

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 Public Service Company of North Carolina, Incorporated x

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

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

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, or non-accelerated filers (as defined in Exchange Act Rule 12b-2).  

SCANA Corporation	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨
South Carolina Electric & Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x
Public Service Company of North Carolina, Incorporated	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes ¨ No x

South Carolina Electric & Gas Company Yes o No x Public Service Company of North Carolina, Incorporated Yes o No x

The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $4.8 billion at June 30, 2005, based on the closing price of $42.71 per share. Each of the other registrants is a wholly owned subsidiary of SCANA Corporation and has no voting stock other than its common stock. A description of registrants' common stock follows:

Registrant	Description of Common Stock	Shares Outstanding at February 20, 2006
SCANA Corporation	Without Par Value	115,032,759
South Carolina Electric & Gas Company	$4.50 Par Value	40,296,147(a)
Public Service Company of North Carolina, Incorporated	Without Par Value	1,000(a)

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

Documents incorporated by reference: Specified sections of SCANA Corporation's 2006 Proxy Statement, in connection with its 2006 Annual Meeting of Shareholders, are incorporated by reference in Part III hereof.

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

Public Service Company of North Carolina, Incorporated 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).

TABLE OF CONTENTS

		Page
DEFINITIONS		4
PART I
Item 1.	Business	5
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	22
Item 4.	Submission of Matters to a Vote of Security Holders	25
Executive Officers of SCANA Corporation		26
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	29
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	30
	South Carolina Electric & Gas Company	94
	Public Service Company of North Carolina, Incorporated	140
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	162
Item 9A.	Controls and Procedures	162
Item 9B.	Other Information	165
PART III
Item 10.	Directors and Executive Officers of the Registrants	166
Item 11.	Executive Compensation	169
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	175
Item 13.	Certain Relationships and Related Transactions	176
Item 14.	Principal Accountant Fees and Services	177
PART IV
Item 15.	Exhibits and Financial Statement Schedules	178
SIGNATURES		180
Exhibit Index		182

2

DEFINITIONS

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

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

3

PART I

ITEM 1. BUSINESS

CORPORATE STRUCTURE

SCANA CORPORATION, a holding company, owns the following significant direct, wholly-owned subsidiaries.

SOUTH CAROLINA ELECTRIC & GAS COMPANY generates and sells electricity to retail customers and purchases, sells and transports natural gas to retail customers.

SOUTH CAROLINA GENERATING COMPANY, INC. owns and operates Williams Station and sells electricity solely to SCE&G.

SOUTH CAROLINA FUEL COMPANY, INC. acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowances.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED, doing business as PSNC Energy, purchases, sells and transports natural gas to retail customers.

SOUTH CAROLINA PIPELINE CORPORATION purchases, sells and transports natural gas to wholesale and industrial customers and owns and operates two LNG plants for the liquefaction, storage and regasification of natural gas.

SCG PIPELINE, INC. transports natural gas in Georgia and South Carolina.

SCANA COMMUNICATIONS, INC. provides fiber optic telecommunications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia.

SCANA ENERGY MARKETING, INC. markets natural gas, primarily in the Southeast, and provides energy-related risk management services. Through its SCANA Energy division, SEMI markets natural gas in Georgia's retail natural gas market.

SERVICECARE, INC. provides service contracts on home appliances and heating and air conditioning units.

PRIMESOUTH, INC. provides management and maintenance services for power plants and a non-affiliated synthetic fuel production facility.

SCANA SERVICES, INC. provides administrative, management and other services to the subsidiaries and business units within SCANA.

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

4

ORGANIZATION

SCANA, a South Carolina corporation having general business powers, is a holding company and was incorporated in 1984. SCANA holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G. SCANA and its subsidiaries had full-time, permanent employees as of February 20, 2006 and 2005 of approximately 5,628 and 5,550, respectively. SCE&G was incorporated under the laws of South Carolina in 1924, and is an operating public utility. SCE&G had full-time, permanent employees as of February 20, 2006 and 2005 of approximately 2,865 and 2,775, respectively. Prior to being acquired by SCANA in 2000, PSNC Energy was incorporated under the laws of North Carolina in 1938. PSNC Energy is now incorporated under the laws of South Carolina, and is an operating public utility in North Carolina with full-time, permanent employees as of February 20, 2006 and 2005 of approximately 700.

INVESTOR INFORMATION

SCANA's, SCE&G's and PSNC Energy'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. The information found on SCANA's website is not part of this or any other report filed with or furnished to the SEC.

SEGMENTS OF BUSINESS

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

Information with respect to major segments of business is contained in Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 11) and PSNC Energy (Note 9). All such information is incorporated herein by reference.

Regulated Utilities

SCE&G is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase, sale and transport at retail of natural gas. SCE&G's business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air conditioning and heating requirements, and sales of natural gas are higher in the winter months due to heating requirements. SCE&G's electric service area extends into 26 counties covering more than 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 34 of the 46 counties in South Carolina and covers more than 22,000 square miles. The total population of the counties representing the combined service area is more than 3.0 million. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries in the areas served by SCE&G include synthetic fibers, chemicals, fiberglass, paper and wood, metal fabrication, stone, clay and sand mining and processing and textile manufacturing.

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

Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements.

5

PSNC Energy is a public utility engaged primarily in purchasing, selling and transporting natural gas to approximately 425,400 residential, commercial and industrial customers (as of December 31, 2005). PSNC Energy provides service to its 28 franchised counties covering approximately 12,000 square miles in North Carolina. The industrial customers of PSNC Energy include manufacturers or processors of textiles, chemicals, ceramics and clay products, glass, automotive products, minerals, pharmaceuticals, plastics, metals, electronic equipment, furniture and a variety of food and tobacco products.

SCPC is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G) and industrial customers throughout most of South Carolina. SCPC owns LNG liquefaction and storage facilities. It also supplies the natural gas for SCE&G's gas distribution system. Other resale customers include municipalities and county gas authorities and gas utilities. The industrial customers of SCPC are primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles.

SCG Pipeline provides interstate transportation services for natural gas to southeastern Georgia and South Carolina. SCG Pipeline transports natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG, Inc. at Elba Island, near Savannah, Georgia. The endpoint of the pipeline is at the site of SCE&G's Jasper County Electric Generating Station. In 2006, SCANA expects to merge SCPC with SCG Pipeline, subject to customary closing conditions and FERC approval. See the Overview Section of SCANA’s Management Discussion and Analysis of Financial Condition and Results of Operations.

Nonregulated Businesses

SEMI markets natural gas primarily in the southeast and provides energy-related risk management services. In addition, SCANA Energy, a division of SEMI, markets natural gas to over 475,000 customers (as of December 31, 2005) in Georgia's natural gas market. The GPSC has contracted with SCANA Energy to serve as regulated provider. Currently, over 70,000 of SCANA Energy’s customers are served under the regulated provider contract. This group includes low-income and high credit risk customers. In June 2005 the GPSC voted to retain SCANA Energy as Georgia’s regulated provider of natural gas for a two-year period ending August 31, 2007, with an option by the GPSC to extend the term for an additional year. SCANA Energy's total customer base represents about a 30 percent 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 data center facilities in South Carolina and, through its joint venture with FRC, LLC, has an interest in an additional 1,064 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides ethernet services in South Carolina, as well as tower site construction, management and rental services in South Carolina and North Carolina.

Other significant businesses owned by SCANA are described in the preceding Corporate Structure section.

COMPETITION

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

CAPITAL REQUIREMENTS

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, as well as to expand to meet future demand for electricity and gas, will depend upon their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, if requested.

For a discussion of the impact of various rate matters 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, SCE&G and PSNC Energy.

During the three-year period 2006-2008, SCANA, SCE&G and PSNC Energy expect to meet capital requirements principally through internally generated funds and the incurrence of additional short-term and long-term indebtedness and sales of additional equity securities by SCANA. SCANA, SCE&G and PSNC Energy expect that they have or can obtain adequate sources of financing to meet their projected cash requirements for the next 12 months and for the foreseeable future.

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

6

CAPITAL PROJECTS

In May 2005, SCE&G substantially completed construction of a back-up dam at Lake Murray in order to comply with new federal safety standards mandated by FERC. Construction of the project and related activities cost approximately $275 million, excluding AFC.

For a discussion of contractual cash obligations, financing limits, financing transactions and other related information, see the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the Capital Expansion Program and Liquidity Matters section of Management's Narrative Analysis of Results of Operations for PSNC Energy.

SCANA's ratios of earnings to fixed charges were 2.19, 2.65, 2.82, 0.53 and 4.37 for the years ended December 31, 2005, 2004, 2003, 2002 and 2001, respectively. To achieve a ratio of 1.0 for the year ended December 31, 2002, SCANA would have needed to earn an additional $108.6 million in income before income taxes. SCANA's ratio for 2002 was negatively impacted by the impairment charge related to the acquisition adjustment associated with SCANA’s purchase in 2000 of PSNC Energy and the impairments of SCANA's investments in certain telecommunications securities. For SCE&G these ratios were 2.10, 3.15, 3.01, 3.13 and 3.37 for the same periods. For PSNC Energy these ratios were 3.04, 2.80, 3.37, (7.78) and 2.54 for the same periods. To achieve a ratio of 1.0 for the year ended December 31, 2002, PSNC Energy would have needed to earn an additional $193.2 million in income before income taxes. PSNC Energy's ratio for 2002 was negatively impacted by the impairment charge related to the acquisition adjustment described above.

ELECTRIC OPERATIONS

Electric Sales

SCE&G's sales of electricity by class as a percent of total electric revenues for 2005 and 2004 were as follows:

CLASSIFICATION	2004			2005
Residential		40	%		39	%
Commercial		30	%		29	%
Industrial		17	%		17	%
Sales for resale		4	%		4	%
Other		2	%		2	%
Total Territorial		93	%		91	%
NMST		7	%		9	%
Total		100	%		100	%

Sales for resale include sales to four municipalities and one electric cooperative. Sales under the NMST during 2005 include sales to 49 investor-owned utilities or registered marketers, seven electric cooperatives, two municipalities and three federal/state electric agencies. During 2004 sales under the NMST included sales to 31 investor-owned utilities or registered marketers, seven electric cooperatives, one municipality and three federal/state electric agencies.

During 2005 SCE&G recorded a net increase of approximately 18,500 customers, increasing its total electric customers to approximately 610,000 at year end. A new all-time peak summer demand of 4,820 MW was set on July 27, 2005. The previous all-time peak demand of 4,574 MW was set on July 14, 2004.

For the three-year period 2006-2008, SCE&G's total territorial KWh sales of electricity are projected to increase 2.4% annually, assuming normal weather. SCE&G's total electric customer base is projected to increase 2.2% annually. Over the same three-year period, SCE&G's territorial peak load (summer, in MW) is projected to increase 2.5% annually. SCE&G's goal is to maintain a reserve margin of between 12% and 18%. As of December 31, 2005 the reserve margin was approximately 17%.

Electric Interconnections

SCE&G purchases all of the electric generation of GENCO's Williams Station under a Unit Power Sales Agreement which has been approved by FERC. See Properties-Electric Properties for Williams Station's generating capacity.

SCE&G's transmission system is part of the interconnected grid extending over a large part of the southern and eastern portions of the nation. SCE&G, Virginia Electric and Power Company, Duke Power Company, Carolina Power & Light Company (Progress Energy Carolinas), APGI (Yadkin Division) and Santee Cooper are members of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the Southeastern Electric Reliability Council. This Council provides for coordinated planning for reliability among bulk power systems in the Southeast. SCE&G is also interconnected with Georgia Power Company, Savannah Electric and Power Company, Oglethorpe Power Corporation and the Southeastern Power Administration's Clarks Hill Project. For a discussion of the impact certain legislative and regulatory initiatives may have on SCE&G's transmission system, see Electric Operations within the Overview section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

7

Fuel Costs and Fuel Supply

The following table sets forth the average cost of nuclear fuel, coal and gas and the weighted average cost of all fuels (including oil) for the years 2003-2005.

	Cost of Fuel Used
	2003		2004		2005
Per MMBTU:
Nuclear	$	.53	$	.50	$	.46
Coal-SCE&G		1.68		1.92		2.36
Coal-GENCO		1.75		2.12		2.43
Gas-SCE&G		7.02		7.31		10.30
All Fuels (weighted average)		1.58		1.96		2.53
Per Ton:
Coal-SCE&G	$	42.06	$	47.49	$	58.51
Coal-GENCO		44.30		52.69		60.68
Per MCF:
Gas-SCE&G	$	7.76	$	7.81	$	10.91

 The following table shows the sources and approximate percentages of total MWh generation by each category of fuel for the years 2003-2005 and the estimates for the years 2006-2008.

	% of Total MWh Generated
	Actual									Estimated
	2003			2004			2005			2006			2007			2008
Coal		70	%		68	%		68	%		69	%		66	%		63	%
Nuclear		21	%		21	%		19	%		19	%		20	%		18	%
Hydro		6	%		4	%		5	%		5	%		5	%		5	%
Natural Gas & Oil		3	%		7	%		8	%		7	%		9	%		14	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

Coal is used at five of SCE&G's fossil fuel-fired plants and GENCO's Williams Station. Unit train deliveries are used at all of these plants and in some cases truck deliveries are used. On December 31, 2005 SCE&G had approximately a 46-day supply of coal in inventory and GENCO had approximately a 27-day supply.

Coal is obtained through supply contracts and purchases on the spot market. Spot market purchases are expected to continue for coal requirements in excess of those provided by existing contracts or when spot market prices are favorable.

Contract coal is purchased from 11 suppliers located in eastern Kentucky, Tennessee, West Virginia and southwest Virginia. Contract commitments, which expire at various times through 2009, are approximately 6.5 million tons annually, which is 94% of total expected coal purchases for 2006. Sulfur restrictions on the contract coal range from 1.0% to 1.5%.

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

SCE&G has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station through 2008. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies:

Commitment	Contractor	Remaining Regions(a)	Expiration Date
Enrichment	United States Enrichment Corporation(b)	19-20	2008
Fabrication	Westinghouse Electric Corporation	19-22	2011

^(a)A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region 18 was loaded in 2005.

^(b)Contract provisions for the delivery of enriched uranium product encompass supply, conversion and enrichment services.

SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent fuel output for the life of Summer Station (including the license extension discussed below) through dry cask storage or other technology as it becomes available. In addition, there is sufficient on-site storage capacity over the life of Summer Station to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract and related litigation with the DOE regarding disposal of spent fuel, see Nuclear Fuel Disposal within the Environmental Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

8

GAS OPERATIONS

Gas Sales-Regulated

Sales of natural gas by class as a percent of total regulated gas revenues for 2005 and 2004 were as follows:

	SCANA						SCE&G						PSNC Energy
CLASSIFICATION	2004			2005			2004			2005			2004			2005
Residential		40.8	%		40.6	%		38.8	%		36.6	%		59.3	%		58.3	%
Commercial		24.7	%		25.5	%		32.3	%		32.3	%		28.9	%		29.4	%
Industrial		29.3	%		29.6	%		28.1	%		30.6	%		6.5	%		8.1	%
Sales for Resale		1.5	%		1.3	%		-			-			-			-
Transportation Gas		3.7	%		3.0	%		0.8	%		0.5	%		5.3	%		4.2	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

For the three-year period 2006-2008, SCANA's total consolidated sales of regulated natural gas in DTs are projected to increase 1.4% annually, assuming normal weather. Residential DT sales are projected to increase 1.7% annually, commercial sales 1.4% and industrial sales 1.3%. Sales for resale are not expected to increase significantly. SCANA's total consolidated natural gas customer base is projected to increase 2.0% annually.

During 2005 SCANA recorded a net increase of approximately 23,500 regulated gas customers, increasing its regulated gas customers to approximately 717,000. SCE&G recorded a net increase of approximately 7,300 gas customers, increasing its total gas customers to approximately 292,000. PSNC Energy recorded a net increase of approximately 16,300 customers, increasing its total customers to approximately 425,000.

The demand for gas is affected principally by the weather and the price relationship between gas and alternate fuels.

SCPC, operating wholly within South Carolina, provides natural gas utility and transportation services for its industrial customers, and supplies natural gas to SCE&G and other wholesale purchasers. SCG Pipeline, operating in South Carolina and Georgia, transports gas to SCE&G's Jasper County Electric Generating Station. In 2006, SCANA expects to merge SCPC and SCG Pipeline. See the Overview Section of SCANA's Management Discussion and Analysis of Financial Condition and Results of Operations.

Gas Cost, Supply and Curtailment Plans

South Carolina

SCPC purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. The gas is brought to South Carolina through transportation agreements with Southern Natural (expiring in 2010) and Transco (expiring in 2008 and 2017). The daily volume of gas that SCPC is entitled to transport under these contracts on a firm basis is 188 MMCF from Southern Natural and 93 MMCF from Transco. Of these daily amounts, 3.5 MMCF from Southern Natural and 1.9 MMCF from Transco have been temporarily released to the City of Orangeburg, and 22.3 MMCF from Southern Natural have been temporarily released to Patriots Energy Group. SCPC also had an additional firm service contract with Southern Natural (expiring in 2017) for 50 MMCF per day which was permanently assigned to SCE&G in February 2005 for use in electric generation. Additional natural gas volumes are brought to SCPC's system as capacity is available for interruptible transportation. SCE&G, under contract with SCPC, is entitled to receive a daily contract demand of 313,188 DTs for resale to SCE&G's customers. The contract allows SCE&G to receive amounts in excess of this demand based on availability. SCE&G, under a separate contract with SCPC, is entitled to receive daily contract demand of 40,410 DTs of supplemental unbundled resale transportation peaking service. In addition, SCE&G, under contract with SEMI, is entitled to receive a daily contract demand of 120,000 DTs for use in electric generation. SCG transports the gas to SCE&G under a separate contract.

During 2005 SCPC's average cost per MCF of natural gas purchased for resale, including firm service demand charges, was $9.47, compared to $7.21 during 2004. SCE&G's average cost per MCF was $10.29 and $7.96 during 2005 and 2004, respectively.

SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.

To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCPC 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 1,740 MMCF (liquefied equivalent) of gas were in storage at December 31, 2005. Additionally, SCPC has contracted for 6,293 MMCF of natural gas storage space, of which 204 MMCF have been temporarily released to Patriots Energy Group for a period of two years. Approximately 5,402 MMCF of gas were in storage on December 31, 2005.

9

The SCPSC has established allocation priorities applicable to the firm and interruptible capacities of SCPC. These curtailment plan priorities apply to SCPC's direct industrial customers and resale distribution customers, including SCE&G.

North Carolina

PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at current price indices and on a long-term basis for reliability assurance at index prices plus a reservation charge. The gas is brought to North Carolina through transportation agreements with Transco and Dominion Transmission, Inc. with expiration dates ranging through 2016. The daily volume of gas that PSNC Energy is entitled to transport under these contracts on a firm basis is 259,894 DT from Transco and 30,331 DT from Dominion Transmission. In addition, PSNC Energy is entitled to firm transportation service on the Patriot Extension Project, a project of East Tennessee Natural Gas Company, and firm storage service on the Saltville Storage Project, an affiliate of East Tennessee Natural Gas Company, that provide an aggregate daily demand of 30,000 DT.

During 2005 PSNC Energy's average cost per DT of natural gas purchased for resale, including firm service demand charges, was $10.63 compared to $7.95 during 2004.

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 Gas Transmission, Columbia Gas Transmission, Transco and East Tennessee Natural Gas Company provide for storage capacity of approximately 12,000 MMCF. Approximately 9,700 MMCF were in storage at December 31, 2005. In addition, PSNC Energy's own LNG facility is capable of storing the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day. Approximately 590 MMCF (liquefied equivalent) were in storage at December 31, 2005. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,100 MMCF (liquefied equivalent) were in storage at December 31, 2005.

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

Gas Marketing-Nonregulated

SEMI's activities are primarily focused in the Southeast, where SEMI markets natural gas and provides energy-related risk management services. In addition, SCANA Energy, a division of SEMI, markets natural gas to over 475,000 customers (as of December 31, 2005) in Georgia's natural gas market. SCANA Energy's total customer base represents over a 30 percent 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.

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

REGULATION

SCANA is a holding company which, together with its subsidiaries, is subject to the jurisdiction of the SEC and FERC as to the issuance of certain securities, acquisitions and other matters. Certain subsidiaries of SCANA are regulated by state public service commissions or FERC as to the following matters.

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

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

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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.

SCPC is subject to the jurisdiction of the SCPSC as to gas rates, service, accounting and other matters.

SCG Pipeline is subject to the jurisdiction of FERC as to gas 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 gas rates for certain of its customers classified as low-income or high credit risk and as to certain other marketing activities.

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.

Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC authority to issue short-term indebtedness. SCE&G and GENCO have applied to FERC for authorization to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. Until FERC approves such issuances or until December 31, 2007, SCE&G and GENCO may rely on the financing authority formerly provided under the Public Utility Holding Company Act of 1935, which act was repealed effective February 8, 2006.

SCE&G holds licenses under the Federal Water Power Act or the Federal Power Act with respect to all of its hydroelectric projects. The expiration dates of the licenses covering the projects are as follows:

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

In November 2003, FERC granted SCE&G a temporary five-year license extension (until 2010) for the Saluda project at Lake Murray because the FERC-mandated draw-down of Lake Murray was expected to affect studies of normal lake conditions that are required for the relicensing application. The five-year extension allows time for the lake level to return to normal operating conditions and to stabilize in order to conduct meaningful studies that may impact future license requirements. SCE&G is now conducting such studies and is preparing an application for relicensing which it expects to file with FERC in 2007.

At the termination of a license under the Federal Power Act, the United States government may take over the project covered thereby, or FERC may extend the license or issue a license to another applicant. If the federal government takes over a project or FERC issues a license to another applicant, the original licensee is entitled to be paid its net investment in the project, not to exceed fair value, plus severance damages, less excess earnings (as defined by FERC regulations) derived from the project, if any.

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

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

RATE MATTERS

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

SCE&G's and PSNC Energy's gas rate schedules for their residential and small commercial and small industrial customers include a WNA. SCE&G's and PSNC Energy's WNA were approved by the SCPSC and NCUC, respectively, and are in effect for bills rendered during the period November 1 through April 30 of each year. In each case the WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues; however, it does reduce fluctuations in revenues and earnings caused by abnormal weather.

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Fuel Cost Recovery Procedures

The SCPSC has established a fuel cost recovery procedure which determines the fuel component in SCE&G's retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any overcollection or undercollection from the preceding 12-month period. SCE&G has the right to request a formal proceeding at any time should circumstances dictate such a review. In January 2005, in conjunction with an electric rate case, SCPSC approved SCE&G’s request to decrease the fuel component of rates charged to electric customers from 1.821 cents per KWh to 1.764 cents per KWh effective with the first billing cycle in January 2005.  The decrease reflected the effect of placing in base rates the retail portion of the fixed pipeline capacity charges for interstate gas service to the Jasper County Electric Generating Station.  These charges were previously included in the Company’s annual fuel forecast recovered through the fuel adjustment clause.  On April 6, 2005, as part of the annual review of fuel costs, the SCPSC approved SCE&G’s request to increase the cost of fuel component from 1.764 cents per KWh to 2.256 cents per KWh effective the first billing cycle in May 2005. 

SCE&G's gas rate schedules and contracts include mechanisms that allow it to recover from its customers changes in the actual cost of gas. SCE&G's firm gas rates allow for the recovery of the cost of gas, based on projections, as established by the SCPSC in annual gas cost and gas purchase practice hearings.

PSNC Energy operates under two rate provisions in addition to WNA that serve to reduce fluctuations in PSNC Energy's earnings. First, its Rider D rate mechanism allows PSNC Energy to recover, in any manner authorized by the NCUC, margin losses on negotiated gas sales. The Rider D rate mechanism also allows PSNC Energy to recover from customers all prudently incurred gas costs. Effective December 1, 2005, PSNC Energy may also recover certain uncollectible expenses related to gas cost. Second, PSNC Energy operates with full margin transportation rates. These rates allow PSNC Energy to earn the same margin on gas delivered to customers regardless of whether the gas is sold or only transported by PSNC Energy to the customer.

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

SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In a July 2005 order, the SCPSC found that for the period January through December 2004 SCPC’s gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff.

ENVIRONMENTAL MATTERS

Federal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be predicted. For a more complete discussion of how these regulations and standards impact SCANA, SCE&G and PSNC Energy, see the Environmental Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 10B) and PSNC Energy (Note 8A).

OTHER MATTERS

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

ITEM 1A. RISK FACTORS

The risk factors that follow relate in each case to SCANA Corporation and its subsidiaries (SCANA), and where indicated the risk factors also relate to South Carolina Electric & Gas Company and its consolidated affiliates (SCE&G) or Public Service Company of North Carolina, Incorporated and its subsidiaries (PSNC Energy) or both.

Commodity price changes may affect the operating costs and competitive positions of SCANA's, SCE&G's and PSNC Energy's energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.

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

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SCANA, SCE&G and PSNC Energy are subject to complex government rate regulation, which could adversely affect revenues, results of operations and cash flows.

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

SCANA, SCE&G and PSNC Energy are vulnerable to interest rate increases which would increase our borrowing costs, and may not have access to capital at favorable rates, if at all, both of which may adversely affect results of operations, cash flows and financial condition.

Changes in interest rates can affect the cost of borrowing on variable rate debt outstanding, on refinancing of debt maturities and on incremental borrowing to fund new investments. SCANA's business plan, and the business plans of SCE&G and PSNC Energy, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining investment grade debt ratings. The liquidity of SCANA, SCE&G and PSNC Energy would be adversely affected by unfavorable changes in the commercial paper market or if bank credit facilities became unavailable at acceptable rates.

SCANA may not be able to reduce its leverage ratio as quickly as planned. This could result in downgrades of SCANA's debt ratings, thereby increasing its borrowing costs and adversely affecting its results of operations, cash flows and financial condition.

SCANA's leverage ratio of debt to capital increased significantly following its acquisition in 2000 of PSNC Energy, and was approximately 56% at December 31, 2005. SCANA has publicly announced its desire to reduce this leverage ratio to between 50% to 52%, but SCANA's ability to do so depends on a number of factors. If SCANA is not able to reduce its leverage ratio, SCANA's debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.

Operating results may be adversely affected by abnormal weather.

SCANA, SCE&G and PSNC Energy 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 are milder than normal. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of SCANA, SCE&G and PSNC Energy. In addition, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

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

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

SCANA, SCE&G and PSNC Energy are subject to risks associated with changes in business climate which could limit access to capital, thereby increasing costs and adversely affecting results of operations, cash flows and financial condition.

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

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SCANA, SCE&G and PSNC Energy 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.

SCANA, SCE&G and PSNC Energy 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.

A downgrade in the credit rating of SCANA, SCE&G or PSNC Energy could negatively affect its ability to access capital and to operate its businesses, thereby adversely affecting results of operations, cash flows and financial condition.

Standard & Poor's Ratings Services (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) rate SCANA's long-term senior unsecured debt at BBB+, A3 and A-, respectively. The S&P and Fitch ratings carry a stable outlook while the Moody's rating outlook is negative. S&P, Moody's and Fitch rate SCE&G's long-term senior secured debt at A-, A1 and A+, respectively, with a stable outlook at S&P and Fitch and a negative outlook at Moody's. S&P and Moody's rate PSNC's long-term senior unsecured debt at A- and A2, respectively, with a stable outlook. Fitch does not rate PSNC Energy. 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 and Moody's rate the short-term debt of SCE&G and PSNC Energy at A-2 and P-1, respectively, and Fitch rates the short-term debt of SCE&G at F-1. If these short-term ratings were to decline, it could significantly limit access to the commercial paper market and other sources of liquidity.

Changes in the environmental laws and regulations to which SCANA, SCE&G and PSNC Energy are subject could increase costs or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.

SCANA's, SCE&G's and PSNC Energy's compliance with extensive federal, state and local environmental laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at our facilities. These expenditures have been significant in the past and are expected to increase in the future. Changes in compliance requirements or a more burdensome interpretation by governmental authorities of existing requirements may impose additional costs on us or require us to curtail some of our activities. Costs of compliance with environmental regulations could harm our industry, our business and our results of operations and financial position, especially if emission or discharge limits are reduced, more extensive permitting requirements are imposed or additional regulatory requirements are imposed.

Changing regulatory and energy marketing structures could affect the ability of SCANA and SCE&G to compete in our electric markets, thereby adversely impacting results of operations, cash flows and financial condition.

The Energy Policy Act of 2005 (the “Energy Policy Act”) became law in August 2005. The Energy Policy Act provides, among other things, for enforceable mandatory reliability standards for transmission systems. In February 2006 FERC issued final rules to implement the electric reliability provisions of the Energy Policy Act. The Company is reviewing these rules and will monitor their implementation to determine the impact they will have on SCE&G's access to or cost of power for its native load customers and for its marketing of power outside its service territory. Management is unable to predict the impact that the final rules, the timing of their implementation, or any future regulatory initiatives could have on results of operations, cash flows and financial condition, though such impact could be significant.

Problems with operations could cause us to incur substantial costs, thereby adversely impacting results of operations, cash flows and financial condition.

As the operator of power generation facilities, SCE&G could incur problems such as the breakdown or failure of power generation equipment, transmission lines, other equipment or processes which would result in performance below assumed levels of output or efficiency. The failure of a power generation facility may result in SCE&G purchasing replacement power at market rates. These purchases are subject to state regulatory prudency reviews for recovery through rates.

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

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

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

The V.C. Summer nuclear plant, operated by SCE&G, provided approximately 5.0 million MWh, or 19% of our generation capacity, in 2005. As such, SCE&G is subject to various risks of nuclear generation, which include the following:

·   The potential harmful effects on the environment and human health resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;

·   Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

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

·   Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable

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ITEM 2. PROPERTIES

SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G. It also has an investment in one LLC which operates a cogeneration facility in Charleston, South Carolina.

SCE&G's bond indentures, securing the First and Refunding Mortgage Bonds and First Mortgage Bonds issued thereunder, constitute direct mortgage liens on substantially all of its property. GENCO's Williams Station is also subject to a first mortgage lien.

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

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

  

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ELECTRIC PROPERTIES

Information on electric generating facilities, all of which are owned by SCE&G except as noted, is as follows:

Facility	Present Fuel Capability	Location	Year In-Service	Net Generating Capacity (Summer Rating) (MW)
Steam Turbines
Summer(1)	Nuclear	Parr, SC	1984	644
McMeekin	Coal/Gas	Irmo, SC	1958	250
Canadys	Coal/Gas	Canadys, SC	1962	416
Wateree	Coal	Eastover, SC	1970	700
Williams(2)	Coal	Goose Creek, SC	1973	615
Cope	Coal	Cope, SC	1996	420
Cogen South(3)		Charleston, SC	1999	90
Combined Cycle
Urquhart(4)	Coal/Gas/Oil	Beech Island, SC	1953/2002	568
Jasper	Gas/Oil	Hardeeville, SC	2004	880
Hydro(5)
Saluda		Irmo, SC	1930	206
Fairfield Pumped Storage		Parr, SC	1978	576

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

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

(3) SCE&G receives shaft horse power from Cogen South, LLC to operate SCE&G's generator. Cogen South, LLC is owned 50% by SCANA and 50% by MeadWestvaco.

(4) Two combined-cycle turbines burn natural gas or fuel oil to produce 341 MW of electric generation and use exhaust heat to power two 75 MW turbines at the Urquhart Generating Station. Unit 3 is a coal-fired steam unit.

(5) SCE&G also owns three other hydro units in South Carolina that were placed in service in 1905 and 1914 and have an aggregate net generating capacity of 32 MW.

SCE&G owns nine other combustion turbine peaking units fueled by gas and/or oil located at various sites in SCE&G's service territory. These turbines were placed in service at various times from 1961 to 1999 and have aggregate net generating capacity of 365 MW.

SCE&G owns 440 substations having an aggregate transformer capacity of 25.8 million KVA (kilovolt-ampere). The transmission system consists of 3,219 miles of lines, and the distribution system consists of 17,777 pole miles of overhead lines and 5,217 trench miles of underground lines.

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NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES

SCE&G's natural gas system consists of approximately 14,350 miles of distribution mains and related service facilities. SCE&G also has propane air peak shaving facilities which can supplement the supply of natural gas by gasifying propane to yield the equivalent of 70 MMCF per day. These facilities can store the equivalent of 241 MMCF of natural gas. In February 2006, under a plan approved by the SCPSC, SCE&G issued a request for proposal to sell these propane air facilities and anticipates that they will be sold during 2006.

SCPC's natural gas system consists of approximately 1,445 miles of transmission pipeline of up to 24 inches in diameter which connect its resale customers distribution systems with transmission systems of Southern Natural and Transco. SCPC 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.

SCG Pipeline’s natural gas system consists of approximately 18 miles of transmission pipeline of up to 20 inches diameter which transports natural gas from Port Wentworth and Elba Island, Georgia to SCE&G’s Jasper County Electric Generating Station in South Carolina.

PSNC Energy's natural gas system consists of approximately 880 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 approximately 8,480 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC Energy owns, through a wholly owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.

ITEM 3. LEGAL PROCEEDINGS

Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2005, are described below. These issues affect SCANA and, to the extent indicated, also affect SCE&G or PSNC Energy.

Environmental Matters

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and other activities continuing until 2011. As of December 31, 2005, SCE&G has spent approximately $21.5 million to remediate the Calhoun Park site, and expects to spend an additional $0.3 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by DHEC. The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of December 31, 2005, SCE&G has spent approximately $4.5 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from this matter is expected to be recoverable through rates.

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SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCANA and SCE&G do not believe that SCE&G’s involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost arising from this matter is expected to be recoverable through rates.

PSNC Energy is responsible for environmental cleanup 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 $7.4 million, which reflects the estimated remaining liability at December 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $3.1 million. SCANA and PSNC Energy believe that all MGP cleanup costs incurred will be recoverable through gas rates.

On January 28, 2004, SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of contract. The contract, entered into in 1983, known as the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract) required the federal government to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, 1998, in exchange for agreed payments fixed in the Standard Contract at particular amounts. As of the date of filing, the federal government has accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government’s breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. On January 9, 2006, SCE&G and Santee Cooper accepted a settlement from DOE which requires the payment by DOE of $9 million to the plaintiffs. The payment is to reimburse the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. The settlement also provides for the plaintiffs to submit an annual application to DOE for the reimbursement of certain costs incurred subsequent to July 31, 2005.

Pending Litigation

In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of SCANA filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 21, 2004, the jury issued an adverse verdict on this matter against SCANA for four causes of action for damages totaling $48 million. In accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.

Post-verdict motions were heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff was ordered to elect a single remedy from the multiple jury awards. In response to the April 2005 election order, the plaintiff elected a remedy with damages totaling $18 million, and SCANA placed the funds in escrow with the Clerk of Court to forestall the accrual of post-judgment interest. The funds held in escrow are recorded within prepayments and other assets on the balance sheet and appear as an investing activity in the statement of cash flows. SCANA believes its accrued liability is still a reasonable estimate. However, SCANA continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

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SCANA is also defending a claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets. A bench trial on the indemnification was held on January 14, 2005, and on August 9, 2005 an order was entered against SCANA in the amount of $2.6 million. SCANA filed a motion and amended motion to vacate or in the alternative to alter or amend or reconsider the order. On December 2, 2005, the judge vacated his earlier award of attorney fees, and further motions to review his order are pending. SCANA has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. Since that time, the plaintiffs have dismissed defendants Duke Energy and Progress Energy and are proceeding against SCE&G only. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may go to trial in 2006. SCANA and SCE&G are confident of the propriety of SCE&G’s actions and intend to mount a vigorous defense. SCANA and SCE&G further believe that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

On May 17, 2004, SCANA and SCE&G were served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit Court (the Court). The plaintiff alleges SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA and SCE&G believe SCE&G’s actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Court granted SCANA and SCE&G’s motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has appealed. SCANA and SCE&G intend to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

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Other Contingency

In 2004 and early 2005, SCANA and certain of its affiliates, like other integrated utilities, were the subject of an investigation by FERC’s Office of Market Oversight and Investigations (OMOI) focusing, among other things, on the relationship between SCE&G’s merchant and transmission functions. These relationships are among those addressed in FERC Order 2004, a primary purpose of which order is to ensure that affiliates of transmission providers have no marketplace advantage over non-affiliated market participants. In connection with that investigation, SCE&G was assessed no monetary damages or penalties; however, under terms of a Settlement and Consent Agreement entered into on April 1, 2005, and approved by FERC order dated April 27, 2005, SCE&G agreed to the implementation of a compliance plan which includes periodic reports to OMOI.

On January 2, 2006, SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgment of SCE&G’s discovery that it may have improperly utilized network transmission services, rather than point-to-point transmission services, for purchases and sales of electricity in violation of SCE&G’s open access transmission tariff and applicable orders under the Federal Power Act that prohibit the use of network transmission service in support of certain “off-system” sales. This acknowledgement was in part the result of SCE&G’s preliminary review of a FERC order issued following its examination of another energy provider in September 2005. Upon further review of that order and a comprehensive analysis, SCE&G has now determined and notified FERC that it did improperly utilize network transmission service in a large number of purchase and sale transactions.

In response to this discovery, SCE&G has notified FERC and has ceased participation in such transactions, has instituted additional self-restrictive procedures as safeguards to ensure full compliance in this area in the future, has committed to certain modifications to its compliance plan, including increased levels of training and monitoring, and is fully cooperating with OMOI to resolve this matter.

As of December 31, 2005, SCE&G has recorded a loss accrual in the amount of approximately $0.8 million based on its estimation of net revenues from these transactions that occurred after the date of the Settlement and Consent Agreement and that might be subject to disgorgement pursuant to FERC orders. However, there remains uncertainty as to what additional actions may be taken by FERC. Potential actions could include further modifications to the compliance plan or other non-monetary remedies. In addition to the disgorgement of profits, such remedies could also include penalties of up to a maximum of $1 million per violation or per day since August 8, 2005, the effective date of the Energy Policy Act of 2005. SCE&G estimates that there were approximately 1,200 of these transactions since August 8, 2005, that, despite the immaterial profits from the transactions, could be deemed in violation of FERC's rule on the use of network transmission service.  In light of SCE&G's self-reporting and other cooperation in the investigation of this matter, SCE&G's belief that no market participants or customers of SCE&G were harmed or disadvantaged by the transactions, and SCE&G’s institution of appropriate safeguards referred to above, SCE&G does not believe that such sanctions are warranted. Nonetheless, SCE&G cannot predict what, if any, actions FERC will take with respect to this matter, and is unable to determine if the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.

SCANA, SCE&G and PSNC Energy are also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without material loss.

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

Not Applicable.

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EXECUTIVE OFFICERS OF SCANA CORPORATION

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

Name	Age	Positions Held During Past Five Years	Dates
William B. Timmerman	59	Chairman of the Board, President and Chief Executive Officer	*-present
Joseph C. Bouknight	53	Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA	2004-present *-2004
George J. Bullwinkel	57	President and Chief Operating Officer-SEMI President and Chief Operating Officer-ServiceCare President and Chief Operating Officer-SCI President and Chief Operating Officer-SCPC and SCG Pipeline Senior Vice President-Governmental Affairs and Economic Development	2004-present 2002-present *-present 2002-2004 *-2002
Sarena D. Burch	48	Senior Vice President-Fuel Procurement and Asset Management-SCE&G, PSNC Energy and SCPC Deputy General Counsel and Assistant Secretary-SCANA Services	2003-present *-2003
Stephen A. Byrne	46	Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G Senior Vice President-Nuclear Operations	2004-present *-2004
Paul V. Fant	52	Senior Vice President-SCANA Services Senior Vice President Transmission Services - SCE&G President and Chief Operating Officer-SCPC and SCG Pipeline Executive Vice President-SCPC Executive Vice President-SCG Pipeline	2004-present 2004-present 2004-present *-2004 2002-2004
Sharon K. Jenkins	48	Senior Vice President-Marketing and Communications-SCANA Services Vice President, Marketing-Wireless and Broadband Systems Division-Motorola, Inc.-Austin, TX	2003-present *-2003
Neville O. Lorick	55	President and Chief Operating Officer-SCE&G	*-present
Kevin B. Marsh	50	Senior Vice President and Chief Financial Officer President and Chief Operating Officer-PSNC Energy	*-present *-2003
Charles B. McFadden	61	Senior Vice President-Governmental Affairs and Economic Development-SCANA Services Vice President-Governmental Affairs and Economic Development-SCANA Services	2003-present *-2003
Francis P. Mood, Jr.	68	Senior Vice President, General Counsel and Assistant Secretary Attorney, Haynsworth Sinkler Boyd, P.A.-Columbia, SC	2005-present *-2005

*Indicates position held at least since March 1, 2001.

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PART II

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

AND ISSUER PURCHASES OF EQUITY SECURITIES

COMMON STOCK INFORMATION

SCANA Corporation

	2005				2004
	4th Qtr.	3rd Qtr.	2nd Qtr.	1st Qtr.	4th Qtr.	3rd Qtr.	2nd Qtr.	1st Qtr.
Price Range (New York Stock Exchange Composite Listing):
High	$43.37	$43.65	$43.30	$40.04	$39.71	$38.09	$36.88	$36.29
Low	37.79	39.90	36.56	36.70	36.39	35.66	32.82	33.42

The principal market for SCANA common stock is the New York Stock Exchange, using the ticker symbol SCG. The corporate name SCANA is used in newspaper stock listings. At February 20, 2006 SCANA common stock totaling 115,032,759 shares were held by approximately 35,957 stockholders of record.

SCANA declared quarterly dividends on its common stock of $.39 per share and $.365 per share in 2005 and 2004, respectively. On February 16, 2006, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.42 per share, an increase of 7.7%. The new dividend is payable April 1, 2006 to stockholders of record on March 10, 2006.

SCE&G and PSNC Energy

All of SCE&G's and PSNC Energy's common stock is owned by SCANA and has no market. During 2005 and 2004 SCE&G paid $150.5 million and $150.0 million, respectively, in cash dividends to SCANA. During each of 2005 and 2004, PSNC Energy paid $14.5 million in cash distributions/dividends to SCANA.

SECURITIES RATINGS (As of February 20, 2006)

	SCANA (1)	SCE&G (1)				PSNC Energy (2)
Rating Agency	Senior Unsecured	Senior Secured	Senior Unsecured	Preferred Stock	Commercial Paper	Senior Unsecured	Commercial Paper
Moody's	A3	A1	A2	Baa1	P-1	A2	P-1
Standard & Poors (S&P)	BBB+	A-	BBB+	BBB	A-2	A-	A-2
Fitch	A-	A+	A	A	F-1	NR	NR

⁽¹⁾S&P and Fitch ratings carry a stable outlook. Moody's outlook is negative.

⁽²⁾All ratings carry a stable outlook.

Additional information regarding these securities is provided in Notes 4, 5 and 7 to the consolidated financial statements for SCANA and SCE&G and Notes 4 and 5 to the consolidated financial statements for PSNC Energy.

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Securities ratings used by Moody's, Standard & Poors and Fitch are as follows:

Long-term (investment grade)			Short-term
Moody's (3)	S&P (4)	Fitch (4)	Moody's	S&P	Fitch
Aaa	AAA	AAA	Prime-1 (P-1)	A-1	F-1
Aa	AA	AA	Prime-2 (P-2)	A-2	F-2
A	A	A	Prime-3 (P-3)	A-3	F-3
Baa	BBB	BBB	Not Prime	B	B
				C	C
				D	D

⁽³⁾Additional Modifiers: 1, 2, 3 (Aa to Baa)

⁽⁴⁾Additional Modifiers: +/- (AA to BBB)

A security rating should be evaluated independently of other ratings and is not a recommendation to buy, sell or hold securities. In addition, security ratings are subject to revision or withdrawal at any time by the assigning rating organization.

For a discussion of provisions that could limit the payment of cash dividends, see Note 6 to the consolidated financial statements for SCANA and SCE&G. For a summary of equity securities issuable under SCANA's compensation plans at December 31, 2005, see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

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ITEM 6. SELECTED FINANCIAL AND OTHER STATISTICAL DATA

	SCANA						SCE&G
As of or for the Year Ended December 31,	2005	2004	2003		2002	2001	2005	2004	2003		2002		2001
	(Millions of dollars, except statistics and per share amounts)
Statement of Operation Data
Operating Revenues	$4,777	$3,885	$3,416	$2,954		$3,451	$2,421	$2,089		$1,832		$1,683		$1,715
Operating Income	436	596	551	514		528	312	475		440		431		439
Other Income (Expense)	(162)	(219)	(138)	(397)		309	(121)	(111)		(101)		(90)		(86)
Income Before Cumulative Effect of Accounting Change	320	257	282	88		539	258	232		220		219		222
Net Income (Loss) (1)	320	257	282	(142)		539	258	232		220		219		222
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions)	113.8	111.6	110.8	106.0		104.7	n/a	n/a		n/a		n/a		n/a
Basic and Diluted Earnings (Loss) Per Share (1)	$2.81	$2.30	$2.54	$(1.34)		$5.15	n/a	n/a		n/a		n/a		n/a
Dividends Declared Per Share of Common Stock	$1.56	$1.46	$1.38	$1.30		$1.20	n/a	n/a		n/a		n/a		n/a
Balance Sheet Data
Utility Plant, Net	$6,734	$6,762	$6,417	$5,474		$5,263	$5,580	$5,621		$5,293		$4,729		$4,065
Total Assets	9,519	9,006	8,458	8,074		7,822	7,366	6,985		6,628		5,958		5,138
Capitalization:
Common equity	$2,677	$2,451	$2,306	$2,177		$2,194	$2,362	$2,164		$2,043		$1,966		$1,750
Preferred Stock (Not subject to purchase or sinking funds)	106	106	106	106		106	106	106		106		106		106
Preferred Stock, net (Subject to purchase or sinking funds)	8	9	9	9		10	8	9		9		9		10
SCE&G—Obligated Mandatorily Redeemable
Preferred Securities of SCE&G Trust I	-	-	-	50		50	-	-		-		50		50
Long-term Debt, net	2,948	3,186	3,225	2,834		2,646	1,856	1,981		2,010		1,604		1,486
Total Capitalization	$5,739	$5,752	$5,646	$5,176		$5,006	$4,332	$4,260		$4,168		$3,735		$3,402
Other Statistics
Electric:
Customers (Year-End)	609,971	585,264	570,940	560,224		547,388	610,025	585,326		570,994		560,248		547,411
Total sales (Million KWh)	25,140	25,031	22,516	23,085		22,928	25,158	25,050		22,531		23,085		22,928
Generating capability—Net MW (Year-End)	5,808	5,817	4,880	4,866		4,520	5,808	5,817		4,880		4,866		4,520
Territorial peak demand—Net MW	4,820	4,574	4,474	4,404		4,196	4,820	4,574		4,474		4,404		4,196
Regulated Gas:
Customers (Year-End)	714,794	693,172	672,849	657,950		647,988	291,607	284,355		278,463		274,334		269,329
Sales, excluding transportation (Thousand Therms)	1,106,526	1,124,555	1,205,730	1,354,400		1,183,463	410,700	399,601		399,392		398,991		368,632
Retail Gas Marketing:
Retail customers (Year-End)	479,382	472,468	415,573	374,872		385,581	n/a	n/a		n/a		n/a		n/a
Firm customer deliveries (Thousand Therms)	379,913	379,712	356,256	337,858		359,602	n/a	n/a		n/a		n/a		n/a
Nonregulated interruptible customer deliveries
(Thousand Therms)	1,010,066	917,875	735,902	852,608		1,119,719	n/a	n/a		n/a		n/a		n/a

⁽¹⁾ Reflects write-down of $230 million for goodwill impairment, recorded as the cumulative effect of an accounting change, in 2002 on adoption of SFAS 142.

25

SCANA CORPORATION

			Page
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		31
		Overview	31
		Results of Operations	35
		Liquidity and Capital Resources	43
		Environmental Matters	47
		Regulatory Matters	50
		Critical Accounting Policies and Estimates	52
		Other Matters	54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		55
Item 8.	Financial Statements and Supplementary Data
		Report of Independent Registered Public Accounting Firm	58
		Consolidated Balance Sheets	59
		Consolidated Statements of Income	61
		Consolidated Statements of Cash Flows	62
		Consolidated Statements of Changes in Common Equity and Comprehensive Income	63
		Notes to Consolidated Financial Statements	64

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

OF OPERATIONS

Statements included in this discussion and analysis (or elsewhere in this annual report) 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. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:(1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility and nonutility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in areas served by subsidiaries of SCANA Corporation (SCANA, and together with its subsidiaries, the Company), (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities for the Company's regulated and diversified subsidiaries, (7) the results of financing efforts, (8) changes in the Company's accounting policies, (9) weather conditions, especially in areas served by the Company's subsidiaries, (10) performance of the Company's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the SEC, including those risks described in Item 1A, Risk Factors. The Company disclaims any obligation to update any forward-looking statements.

OVERVIEW

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

The activities of the Company’s significant business segments are conducted primarily in the areas indicated on the following map, and as further described in this overview section.

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

% of Revenues	2005			2004			2003
Regulated		69	%		71	%		73	%
Nonregulated		31	%		29	%		27	%
% of Net Income (Loss)		2005			2004(a	)		2003
Regulated		92	%		106	%		92	%
Nonregulated		8	%		(6	)%		8	%
% of Assets		2005			2004			2003
Regulated		94	%		94	%		93	%
Nonregulated		6	%		6	%		7	%

(a) In 2004, net income for regulated businesses totaled $272.0 million and net loss for nonregulated businesses totaled $14.9 million. Net loss for nonregulated businesses included impairments and losses recognized on the sale of certain of the Company’s telecommunications investments ($29.8 million, net of tax) and a charge related to pending litigation associated with the Company’s 1999 sale of its propane assets ($11.1 million, net of taxes). See Results of Operations for more information.

Key earnings drivers for the Company over the next five years will be additions to utility rate base at SCE&G and PSNC Energy, driven primarily by capital expenditures for environmental facilities, new generating capacity and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth in each of the regulated utility businesses, consistent earnings growth in the natural gas marketing business in Georgia, controlling interest expense through continued debt reduction and limiting the growth of operation and maintenance expenses.

Electric Operations

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 and distribution of electricity in South Carolina. At December 31, 2005 SCE&G provided electricity to approximately 610,000 customers in an area covering approximately 17,000 square miles. GENCO owns and operates a coal-fired generation station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements.

Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. In January 2005, as a result of an electric rate case, SCE&G’s allowed return on equity was lowered from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. See further discussion at Liquidity and Capital Resources. Demand for electricity is primarily affected by weather, customer growth and the economy.  SCE&G is able to recover the cost of fuel used in electric generation through retail customers' bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

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

In February 2006 FERC issued final rules to implement the electric reliability provisions of the Energy Policy Act. The Company is reviewing these rules and will monitor their implementation to determine the impact they may have on SCE&G’s access to or cost of power for its native load customers and for its marketing of power outside its service territory. The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities.

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

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Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy, and is primarily engaged in the purchase, transmission and sale of natural gas in portions of North Carolina and South Carolina. At December 31, 2005 this segment provided natural gas to approximately 717,000 customers in an area covering approximately 34,000 square miles.

Operating results for gas distribution are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. For SCE&G this allowed return on equity was 12.25% for January 1 through October 31, 2005, when it was lowered to 10.25% as a result of a rate case. For PSNC Energy this allowed return on equity was 11.4% for all of 2005. In the second quarter of 2006, PSNC Energy plans to file with the NCUC a request to increase base rates. Specific details related to the timing and size of the request have not been finalized.

Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact the Company’s ability to retain large commercial and industrial customers. Significant supply disruptions did occur in September and October 2005 as a result of hurricane activity in the Gulf of Mexico, resulting in the curtailment during the period of most large commercial and industrial customers with interruptible supply agreements. While supply disruptions are no longer being experienced, the price of natural gas remains volatile and has resulted in short-term competitive pressure. The long-term impact of volatile gas prices and gas supply has not been determined.

Gas Transmission

For 2005 the gas transmission segment was comprised of SCPC, which owns and operates an intrastate pipeline engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G) and industrial customers throughout most of South Carolina. Operating results for 2005 were primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which in 2005 was 12.5% to 16.5%. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth. SCPC supplies natural gas to SCE&G for its resale to gas distribution customers and for certain electric generation needs. SCPC also sells natural gas to large commercial and industrial customers in South Carolina and faces the same competitive pressures as the gas distribution segment for these classes of customers.

In 2006 SCANA expects to merge two of its subsidiaries, SCPC and SCG Pipeline, Inc., into a new company to be called Carolina Gas Transmission Corporation (CGTC). CGTC will operate as an open access transportation-only interstate pipeline company. On February 27, 2006, the merger application was filed with FERC. SCANA does not expect a final decision regarding the merger from FERC before the third quarter of 2006.

Retail Gas Marketing

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to over 475,000 customers (as of December 31, 2005) throughout Georgia. SCANA Energy’s total customer base represents about a 30 percent share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. SCANA Energy’s competitors include affiliates of other large energy companies with experience in Georgia’s energy market as well as several electric membership cooperatives. SCANA Energy’s ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors. In addition, the pipeline capacity available for SCANA Energy to serve industrial and other customers is tied to the market share held by SCANA Energy in the retail market.

As Georgia’s regulated provider, SCANA Energy serves low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC, and it receives funding from the Universal Service Fund for some of the bad debt associated with the low-income group. In June 2005, the Georgia Public Service Commission (GPSC) voted to retain SCANA Energy as Georgia’s regulated provider of natural gas for a two-year period ending August 31, 2007, with an option by the GPSC to extend the term for an additional year. In connection with this contract extension, SCANA Energy has agreed to file financial and other information periodically with the GPSC, and such information will be available at www.psc.state.ga.us. At December 31, 2005, SCANA Energy’s regulated division served over 70,000 customers.

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

SCANA Energy, pursuant to a written agreement, has maintained a long-standing marketing alliance with Cobb Energy Management Corporation (Cobb Energy), an affiliate of Cobb Electric Membership Corporation (Cobb EMC), and other Georgia electric membership cooperatives (collectively, the EMCs) under the terms of which the parties have worked in an exclusive relationship to attract, retain and serve customers for SCANA Energy.  In July 2005, Southern Company Gas, the natural gas marketing affiliate of Southern Company, announced that it had signed a letter of intent to negotiate the sale of its business to a soon to be formed affiliate of Cobb EMC.  In connection with this proposed transaction, Cobb Energy, on behalf of itself and the EMCs, entered into discussions with SCANA Energy to modify the marketing alliance.

As a result of those discussions, effective October 31, 2005, SCANA Energy and the EMCs amended the marketing alliance so that, in an orderly fashion in 2006, the EMCs will transition to SCANA Energy certain call center and customer-related administrative functions, such as billing and collections, which are currently being provided to a portion of SCANA Energy’s customers by the EMCs. During the process and subsequent to the completion of the transition, certain other requirements also must be met by the EMCs until such time as the marketing alliance expires in October 2008.

SCANA Energy believes that its current customer service and billing systems have the capacity to accommodate the additional customers and that it will have the resources in place to assume responsibility for providing these services for its customers. SCANA Energy expects that the transition will have minimal impact on its customers or related customer service functions. However, as noted above, there can be no assurance that SCANA Energy will be able to maintain its current level of customers, and therefore, no assurance that its current level of profitability will be sustained.

Energy Marketing

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 producers and customers.

The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control costs. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth.

RESULTS OF OPERATIONS

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

	2005			2004		2003
Reported (GAAP) earnings per share	$	2.81		$	2.30	$	2.54
Add (Deduct):
Gains from sales of telecommunications investments		(.03	)		-		(.35	)
Losses from sales of telecommunications investments		-			.14		-
Telecommunications investment impairments		-			.13		.31
Charge related to pending litigation		-			.10		-
GAAP-adjusted net earnings from operations per share	$	2.78		$	2.67	$	2.50
Cash dividends declared (per share)	$	1.56		$	1.46	$	1.38

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Discussion of above adjustments:

Realized gains (losses) on telecommunications investments of $.03, $(.14) and $.35 were recognized in 2005 2004 and 2003, respectively, and arose as a result of the Company’s monetization of these telecommunications investments. All significant telecommunications investments have now been monetized. The gain of $.03 per share in 2005 resulted from the receipt in 2005 of additional proceeds from the 2003 sale of the Company’s investment in ITC Holding Company (ITC Holding). These additional proceeds had been held in escrow pending resolution of certain contingencies. The loss of $.14 per share in 2004 related to the sale of substantially all of the Company’s holdings in ITC^DeltaCom, Inc. (ITC^DeltaCom) and Knology, Inc. (Knology) in December of 2004. The gain of $.35 per share in 2003 arose from the sale of the Company’s interest in ITC Holding and the receipt of a minority investment interest in a newly formed entity, Magnolia Holding Company, LLC (Magnolia Holding).

 The Company’s Knology holdings experienced other-than-temporary impairments of $.13 per share in 2004 and $.31 per share in 2003, prior to their monetization in December 2004.

The charge related to pending litigation recognized in 2004 resulted from an unfavorable verdict in a case in which an unsuccessful bidder for the purchase of certain of the Company’s propane gas assets in 1999 alleged breach of contract and related claims. Both parties have appealed the judgment. See also Note 10 to the consolidated financial statements.

Management believes that all of the above adjustments are appropriate in determining the non-GAAP financial performance measure. Management utilizes such measure itself in exercising budgetary control, managing business operations and determining eligibility for incentive compensation payments. Such non-GAAP measure is based on management’s decision that the passive telecommunications investments were not a part of the Company’s core businesses and would not be available to provide earnings on a long-term basis. The non-GAAP measure also provides a consistent basis upon which to measure performance by excluding the effects on per share earnings of transactions involving the Company’s telecommunications investments and the litigation charge related to the sale of a prior business.

Pension Income

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

Millions of dollars	2005		2004		2003
Income Statement Impact:
(Component of) reduction in employee benefit costs	$	4.3	$	2.9	$	(2.3	)
Other income		11.9		10.8		7.9
Balance Sheet Impact:
(Component of) reduction in capital expenditures		1.3		1.0		(0.5	)
Component of (reduction in) amount due to Summer Station co-owner		0.6		0.4		(0.1	)
Total Pension Income	$	18.1	$	15.1	$	5.0

For the last several years, the market value of the Company’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income’s significant increase in 2004 is consistent with overall investment market results. See also the discussion of pension accounting in Critical Accounting Policies and Estimates.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 1.4% of income before income taxes in 2005, 6.8% in 2004 and 7.4% in 2003.

The lower level of AFC for 2005 is primarily due to reductions in the levels of capital expenditures subsequent to the completion of the Jasper County Electric Generation Station in May 2004 and completion of the Lake Murray Dam project in May 2005.

Recognition of Synthetic Fuel Tax Credits

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. These synthetic fuel production facilities were placed in operation in 2000 and 2001. Under an accounting plan approved by the SCPSC in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were deferred until the SCPSC approved its application to offset capital costs of the Lake Murray Dam project as described below.

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In a January 2005 order, the SCPSC approved SCE&G’s request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

 The level of depreciation expense and related tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account is declining as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they have a significant impact on individual line items within the income statement. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment.The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2005 are as follows:

	Recognized 4th Quarter			Year Ended December 31,
Millions of dollars	2005			2005
Depreciation and amortization expense	$	(13.2	)	$	(214.0	)
Income tax benefits:
From synthetic fuel tax credits		10.9			179.0
From accelerated depreciation		5.0			81.8
From partnership losses		1.7			28.9
Total income tax benefits		17.6			289.7
Losses from Equity Method Investments		(4.4	)		(75.7	)
Impact on Net Income		-			-

Electric Operations

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

Millions of dollars	2005		% Change			2004		% Change			2003
Operating revenues	$	1,908.3		13.1	%	$	1,687.7		15.1	%	$	1,466.5
Less: Fuel used in generation		618.3		32.4	%		466.9		39.7	%		334.1
Purchased power		37.2		(26.6	)%		50.7		(20.8	)%		64.0
Margin	$	1,252.8		7.1	%	$	1,170.1		9.5	%	$	1,068.4

• 2005 vs 2004 Margin increased by $41.4 million due to increased retail electric rates that went into effect in January 2005, by $24.8 million due to residential and commercial customer growth and by $16.4 million due to increased off-system sales. These increases were offset by a $2.4 million decrease due to unfavorable weather. Fuel used in generation increased $151.4 million due primarily to the increased cost of coal and natural gas used for electric generation. Purchased power decreased due to greater availability of generation facilities.

• 2004 vs 2003 Margin increased by $47.2 million due to increased off-system sales, by $22.9 million due to increased customer growth and consumption, by $22.3 million due to favorable weather and by $7.1 million due to the increase in retail electric base rates effective February 2003. Fuel used in generation increased by $103.0 million due to increased availability of generation facilities and by $30.0 million due to increased cost of coal. Purchased power decreased due to greater availability of generation facilities.

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

Classification (in thousands)	2005		% Change			2004		% Change			2003
Residential		7,634		2.3	%		7,460		6.6	%		6,998
Commercial		7,047		2.1	%		6,900		4.4	%		6,607
Industrial		6,651		(1.8	)%		6,775		3.5	%		6,548
Sales for resale (excluding interchange)		1,487		(2.5	)%		1,525		6.1	%		1,438
Other		527		0.2	%		526		5.2	%		500
Total territorial		23,346		0.7	%		23,186		5.0	%		22,091
NMST		1,794		(2.8	)%		1,845		*			425
Total		25,140		0.4	%		25,031		11.2	%		22,516

* Greater than 100%

• 2005 vs 2004 Territorial sales volumes increased by 407 MWh primarily due to customer growth partially offset by 261 MWh due to less favorable weather.

• 2004 vs 2003 Territorial sales volumes increased by 334 MWh and 774 MWh due to customer growth and weather, respectively.

Gas Distribution

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

Millions of dollars	2005		% Change			2004		% Change			2003
Operating revenues	$	1,168.6		27.9	%	$	913.9		5.2	%	$	869.0
Less: Gas purchased for resale		894.6		36.6	%		655.1		9.3	%		599.3
Margin	$	274.0		5.9	%	$	258.8		(4.0	)%	$	269.7

• 2005 vs 2004 Margin increased primarily due to customer growth of $6.9 million at PSNC Energy, higher firm margin of $4.7 million at SCE&G and $4.6 million due to increased retail gas base rates at SCE&G which became effective with the first billing cycle in November 2005. These increases were offset by a $0.8 million decrease due to lower interruptible margin and transportation revenue at SCE&G.

• 2004 vs 2003 Margin decreased primarily due to a decrease in SCE&G’s billing surcharge for the recovery of environmental remediation expenses of $5.0 million, lower residential and commercial sales volumes of $2.5 million and $5.1 million due to milder weather. This was partially offset by customer growth at PSNC Energy of $4.0 million.

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

Classification (in thousands)	2005		% Change			2004		% Change			2003
Residential		37,860		1.7	%		37,231		(3.4	)%		38,542
Commercial		27,750		1.8	%		27,271		(1.6	)%		27,715
Industrial		20,833		7.8	%		19,320		(3.9	)%		20,109
Transportation gas		27,698		(1.8	)%		28,216		11.1	%		25,387
Sales for resale		-		*			1		*			1
Total		114,141		1.9	%		112,039		0.3	%		111,754

* Not meaningful

• 2005 vs 2004 Commercial and industrial volumes increased primarily due to more customers buying commodity gas instead of purchasing alternate fuels and instead of transporting gas purchased from others.

• 2004 vs 2003 Residential and commercial sales volumes decreased primarily due to unfavorable consumption patterns. Transportation volumes increased primarily as a result of interruptible customers using gas instead of alternative fuels.

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Gas Transmission

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

Millions of dollars	2005		% Change			2004		% Change			2003
Operating revenues	$	658.0		19.4	%	$	550.9		6.0	%	$	519.8
Less: Gas purchased for resale		604.2		21.6	%		496.9		5.2	%		472.2
Margin	$	53.8		(0.4	)%	$	54.0		13.4	%	$	47.6

• 2005 vs 2004 Operating revenues and gas purchased for resale increased primarily due to higher commodity gas prices.

• 2004 vs 2003 Margin increased primarily due to higher transportation and reservation revenue as a result of new firm transportation contracts.

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

Classification (in thousands)	2005		% Change			2004		% Change			2003
Commercial		54		(52.2	)%		113		5.6	%		107
Industrial		22,748		(20.5	)%		28,625		(8.9	)%		31,436
Transportation		24,801		(1.8	)%		25,252		*			12,262
Sales for resale		43,763		1.9	%		42,946		(9.4	)%		47,391
Total		91,366		(5.7	)%		96,936		6.3	%		91,196

* Greater than 100%

• 2005 vs 2004 Industrial volumes decreased primarily due to higher commodity gas prices relative to alternative fuels.

• 2004 vs 2003 Industrial volumes decreased primarily due to decreased electric generation. Transportation volumes increased by 7.5 million DTs due to a new contract with a firm transportation customer and by 4.9 million DTs due to new transportation contracts with resale customers. Sales for resale volumes decreased primarily due to the previously mentioned new transportation contracts with resale customers.

Retail Gas Marketing

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

Millions of dollars	2005		% Change			2004		% Change			2003
Operating revenues	$	663.8		20.3	%	$	552.0		23.1	%	$	448.3
Net income		24.1		(16.9	)%		29.0		44.3	%		20.1

• 2005 vs 2004 Operating revenues increased primarily as a result of higher average retail prices necessitated by higher commodity cost of gas. Net income decreased primarily due to increased bad debt of $5.9 million, and operating, marketing and customer service expenses of $4.4 million, offsetting a margin increase of $5.2 million, net of taxes.

• 2004 vs 2003 Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $16.7 million, partially offset by increased bad debt of $2.9 million, increased depreciation expense of $0.7 million and higher customer service expenses of $2.0 million.

Delivered volumes for 2005, 2004 and 2003 totaled 37.9 million, 37.9 million and 35.6 million DT, respectively.

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Energy Marketing

Energy Marketing is comprised of the Company’s non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net loss were as follows:

Millions of dollars	2005			% Change			2004			% Change			2003
Operating revenues	$	945.6			58.5	%	$	596.5			43.5	%	$	415.7
Net loss		(0.6	)		70.0	%		(2.0	)		(81.8	)%		(1.1	)

• 2005 vs 2004 Operating revenues increased due to higher market prices and higher sales volume. Net loss decreased primarily due to higher margins of $0.6 million and lower operating expenses of $0.8 million.

• 2004 vs 2003 Operating revenues increased due to higher market prices and higher sales volumes. Net loss increased primarily due to higher operating expenses of $2.0 million partially offset by higher margins of $0.8 million.

  Delivered volumes for 2005, 2004 and 2003 totaled approximately 101.0 million, 91.8 million and 73.6 million DT, respectively.  Delivered volumes increased in 2005 compared to 2004 primarily as a result of increased service to municipalities in South Carolina.  Delivered volumes increased in 2004 compared to 2003 primarily as a result of the commencement of service to the Jasper County Electric Generating Station in 2004, which created 11.2 million DT of additional volume.

Other Operating Expenses

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

Millions of dollars	2005		% Change			2004		% Change			2003
Other operation and maintenance	$	632.0		4.0	%	$	607.5		8.8	%	$	558.3
Depreciation and amortization		509.9		92.3	%		265.1		11.2	%		238.3
Other taxes		145.0		(0.4	)%		145.6		4.6	%		139.2
Total	$	1,286.9		26.4	%	$	1,018.2		8.8	%	$	935.8

• 2005 vs 2004 Other operation and maintenance expenses increased primarily due to increased electric generation major maintenance expenses of $6.7 million, increased expenses associated with the Jasper County Electric Generating Station completed in May 2004 totaling $2.4 million, increased nuclear operating and maintenance expenses of $2.4 million, higher expenses related to regulatory matters of $1.9 million and higher amortization of regulatory assets of $3.6 million. The increases were offset primarily by decreased long-term bonus and incentive plan expenses of $4.8 million and decreased storm damage expenses of $0.9 million. Depreciation and amortization increased approximately $214.0 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits), increased $6.5 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $6.1 million due to normal net property changes at SCE&G. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $17.3 million of additional depreciation and amortization expense in the period.

• 2004 vs 2003 Other operation and maintenance expenses increased primarily due to increased labor and benefit expense of $26.3 million, higher bad debt expense of $5.8 million, increased expenses at the generation plants of $11.0 million, winter storm expense of $2.5 million and increased gas marketing and customer billing costs of $4.2 million, partially offset by increased pension income of $5.2 million. Depreciation and amortization increased by $13.4 million due to completion of the Jasper County Electric Generating Station and $11.1 million as a result of normal net property additions. Other taxes increased primarily due to increased property taxes.

Other Income (Expense)

Components of other income (expense), excluding the equity component of AFC, were as follows:

Millions of dollars	2005			% Change			2004			% Change			2003
Gain (loss) on sale of investments	$	7.2			*		$	(21.0	)		*		$	59.8
Gain on sale of assets		1.7			*			0.7			(41.7	)%		1.2
Impairment of investments		-			*			(26.9	)		(49.3	)%		(53.1	)
Other revenues		248.1			36.9	%		181.2			8.6	%		166.8
Other expenses		(200.3	)		25.2	%		(159.9	)		30.2	%		(122.8	)
Total	$	56.7			*		$	(25.9	)		*		$	51.9

* Greater than 100%

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Gain (loss) on sale of investments increased due to the receipt in 2005 of additional proceeds of $6.0 million from the 2003 sale of the Company’s investment in ITC Holding. These proceeds had been held in escrow pending resolution of certain contingencies. In 2004 the Company recognized a $21 million loss on the sale of investments in Knology and ITC^DeltaCom. In 2003 a $59.8 million gain on sale of investments was recognized in connection with the sale of ITC Holding and the receipt of a minority interest in a newly formed entity (Magnolia Holding). In 2004 impairments of $26.9 million were recorded on Knology, ITC Holding and Magnolia Holding. Impairments in 2003 related to an investment in Knology.

Interest Expense

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

Millions of dollars	2005		% Change			2004		% Change			2003
Interest on long-term debt, net	$	202.8		(2.5	)%	$	208.1		1.4	%	$	205.2
Other interest expense		12.6		*			4.3		(25.9	)%		5.8
Total	$	215.4		1.4	%	$	212.4		0.7	%	$	211.0

* Greater than 100%

• 2005 vs 2004 Interest on long-term debt decreased primarily due to the redemption of outstanding debt in late 2004. Other interest expense increased primarily due to increased short-term debt at SCE&G.

• 2004 vs 2003 Interest expense increased primarily due to slightly higher levels of borrowing outstanding during 2004 until the payment of maturing debt late in the year.

Income Taxes

Income taxes decreased in 2005 compared to 2004 by $240.8 million and decreased $12.4 million in 2004 compared to 2003. Changes in income taxes are primarily due to changes in operating income and other income, although in 2005 the benefits of synthetic fuel credits of $179.0 were also recognized pursuant to the January 2005 electric rate order. The Company’s effective tax rate has been favorably impacted in recent years by the flow-through of state investment tax credits and the equity portion of AFC.

LIQUIDITY AND CAPITAL RESOURCES

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

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G’s allowed return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G’s recovery of construction and operating costs for SCE&G’s new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. The SCPSC also approved recovery over a five-year period of SCE&G’s approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G’s Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year. No such additional depreciation was recognized in 2005, 2004 or 2003.

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In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69%, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25% and became effective with the first billing cycle in November 2005.

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil and nuclear-fueled generation. On February 10, 2006, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) announced their selection of the Summer Station site as the preferred site for a new nuclear plant should nuclear generation be considered the best alternative in the future. Due to the significant lead time required for construction of a nuclear plant, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). The COL application, which is expected to be completed and filed in 2007, would be reviewed by the NRC for an estimated three years. Issuance of a COL would not obligate the joint owners to build a nuclear plant. The final decision to build a nuclear plant will be influenced by several factors, including NRC licensing attainment, construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

The Company’s leverage ratio of debt to capital was 56% at December 31, 2005. The Company’s goal is to reduce this leverage ratio to between 50% and 52%. If the agencies rating the Company’s credit determine that the Company will not be able to achieve sufficient improvement in the leverage ratio, among other measures, these rating agencies may downgrade the Company’s debt. Such a downgrade would adversely affect the interest rate the Company is able to obtain when issuing debt, would increase the rates applicable to the Company’s short-term commercial paper programs and long-term debt and would limit the Company’s access to capital markets. In order to bring the leverage ratio in line with rating agency expectations, the Company may apply cash flows from operations to debt reduction, sell equity securities, or a combination of the two.

 The Company’s current estimates of its cash requirements for construction and nuclear fuel expenditures for 2006-2008, which are subject to continuing review and adjustment, are as follows:

Estimated Cash Requirements

Millions of dollars	2006		2007		2008
SCE&G:
Electric Plant:
Generation (including GENCO)	$	128	$	86	$	193
Transmission		50		44		46
Distribution		115		114		115
Other		18		11		14
Nuclear Fuel		27		25		5
Gas		27		26		31
Common		22		17		7
Other		2		-		-
Total SCE&G		389		323		411
PSNC Energy		70		78		84
Other Companies Combined		44		32		27
Total	$	503	$	433	$	522

The Company’s contractual cash obligations as of December 31, 2005 are summarized as follows:

Contractual Cash Obligations

Millions of dollars	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long-term and short-term debt (including
interest and preferred stock)	$	6,171	$	874	$	925	$	920	$	3,452
Capital leases		2		1		1		-		-
Operating leases		53		15		35		1		2
Purchase obligations		166		152		12		2		-
Other commercial commitments		8,955		1,633		2,207		1,124		3,991
Total	$	15,347	$	2,675	$	3,180	$	2,047	$	7,445

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

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

In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded, and no further contributions are anticipated until after 2010. Cash payments under the health care and life insurance benefit plan were $10.8 million in 2005, and such annual payments are expected to increase to the $13-$14 million range 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 under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

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

The Company anticipates that its contractual cash obligations will be met through internally generated funds, issuance of equity under dividend reinvestment and employee stock ownership plans, the incurrence of additional short-term and long-term indebtedness and other 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.

Cash outlays for 2006 (estimated) and 2005 (actual) for certain expenditures are as follows:

Millions of dollars	2006		2005
Property additions and construction expenditures, net of AFC	$	485	$	385
Nuclear fuel expenditures		18		18
Investments		18		18
Total	$	521	$	421

Financing Limits and Related Matters

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

At December 31, 2005 SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following lines of credit and short-term borrowings outstanding:

Millions of dollars	SCANA			SCE&G			PSNC Energy
Lines of credit (total and unused):
Committed
Short-term	$	350			-			-
Long-term (expires June 2010)		-		$	525		$	125
Uncommitted		103(a	)		78(a	)		-
Short-term borrowings outstanding:
Bank loans/commercial paper (270 or fewer days)	$	25		$	303.1		$	98.6
Weighted average interest rate		4.43	%		4.40	%		4.47	%

(a) SCANA or SCE&G may use $78 million of these lines of credit.

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SCANA Corporation

SCANA has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires customary approvals discussed above, the Indenture under which they are issued contains no specific limit on the amount which may be issued.

 South Carolina Electric & Gas Company

SCE&G’s First and Refunding Mortgage Bond Indenture, dated January 1, 1945 (Old Mortgage) and covering substantially all of its properties, prohibits the issuance of additional bonds (Class A Bonds) unless net earnings (as therein defined) for 12 consecutive months out of the 18 months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2005 the Bond Ratio was 7.03. The Old Mortgage allows the issuance of Class A Bonds up to an additional principal amount equal to (i) 70% of unfunded net property additions (which unfunded net property additions certified to the trustee and other property eligible to be certified as property additions totaled approximately $2.0 billion at December 31, 2005), (ii) retirements of Class A Bonds (which retirement credits totaled $86.0 million at December 31, 2005), and (iii) cash on deposit with the Trustee.

SCE&G is also subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage. At December 31, 2005, $1.2 billion Class A Bonds were on deposit with the Trustee of the New Mortgage and are available to support the issuance of additional New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 2005, the New Bond Ratio was 6.76.

SCE&G’s Restated Articles of Incorporation (the Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders unless net earnings (as therein defined) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2005, the Preferred Stock Ratio was 2.12.

The Articles also require the consent of a majority of the total voting power of SCE&G’s preferred stock before SCE&G may issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed ten percent of the aggregate principal amount of all of SCE&G’s secured indebtedness and capital and surplus (the ten percent test). No such consent is required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes. At December 31, 2005, the ten percent test would have limited issuances of unsecured indebtedness to approximately $419.5 million. Unsecured indebtedness at December 31, 2005, totaled approximately $246.6 million, and was comprised of short-term borrowings and the interest-free borrowing discussed below.

In 2004 and 2005 SCE&G borrowed an aggregate $59 million available under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. Such borrowings are being repaid interest-free over ten years from the initial borrowing. At December 31, 2005 SCE&G had $50.2 million outstanding under the agreement.

Public Service Company of North Carolina, Incorporated

PSNC Energy has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires regulatory approval, the Indenture under which they would be issued contains no specific limit on the amount which may be issued.

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Financing Cash Flows

During 2005 the Company experienced net cash outflows related to financing activities of approximately $131 million primarily due to the reduction of long-term debt and payment of dividends. SCE&G also experienced net cash outflows related to financing activities of approximately $64 million primarily due to the payment of dividends.

The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. Payments received upon termination of such swaps are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. At December 31, 2005, the estimated fair value of the Company’s swaps totaled $0.1 million (gain) related to combined notional amounts of $47.4 million.

In anticipation of the issuance of debt, the Company uses interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, SCE&G paid $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, SCE&G paid $3.5 million upon the termination of a forward starting interest rate swap.

In December 2005, SCE&G entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, an unrealized loss on this treasury lock agreement in the amount of approximately $3.8 million has been recorded within other regulatory assets. Any gain or loss on the ultimate settlement of this swap will be amortized over the life of the debt to which it relates.

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

On February 16, 2006, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.42 per share, an increase of 7.7%. The new dividend is payable April 1, 2006 to stockholders of record on March 10, 2006.

ENVIRONMENTAL MATTERS

Capital Expenditures

For the three years ended December 31, 2005, the Company’s capital expenditures for environmental control totaled $200.2 million. These expenditures were in addition to expenditures included in “Other operation and maintenance” expenses, which were $25.2 million, $21.5 million, and $29.2 million during 2005, 2004 and 2003, respectively. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $66.9 million for 2006 and $314.3 million for the four-year period 2007 through 2010. These expenditures are included in the Company’s construction program, discussed in Liquidity and Capital Resources, and include the matters discussed below.

Electric Operations

In March 2005, the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company will be installing additional air quality controls to meet the CAIR requirements. Installation and operation and maintenance costs are currently being determined. Such costs are likely to be material and are expected to be recoverable through rates.

In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is negotiating with the South Carolina Department of Health and Environmental Control the terms of the state compliance proposals. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review and assessments. Such costs are likely to be material and are expected to be recoverable through rates.

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The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the DOJ has brought suit against a number of utilities in federal court alleging violations of the CAA. At least two of these suits have either been tried or have had substantive motions decided—one favorable to the industry and one not. The one not favorable to the Company is not binding as precedent and the one favorable to the Company likely is precedent and is consistent with current Company interpretation of the law and its resulting maintenance practices. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA, under a stringent rule known as New Source Review (NSR), that maintenance activities undertaken by the utilities over the past 20 or more years constitute “major modifications” which would have required the installation of costly Best Available Control Technology (BACT). SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of “major modifications,” including an exemption for routine repair, replacement or maintenance. On October 27, 2003, EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The new rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. The ultimate application of the final rule to the Company is uncertain. The Company has analyzed each of the activities covered by the EPA’s requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. The current state of continued DOJ enforcement actions is the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any enforcement actions relative to the Company’s, SCE&G’s or GENCO’s compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet CAIR regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $331 million over the 2006-2009 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $4 million in 2009 and $27 million in 2010 and subsequent years. To meet compliance requirements for the years 2011 through 2015, the Company anticipates additional capital expenditures totaling approximately $564 million.

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

Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 ( the “Nuclear Waste Act”) required that the United States government, by January 31, 1998, accept and permanently dispose of high-level radioactive waste and spent nuclear fuel. The Nuclear Waste Act also imposes 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 (Standard Contract) with the DOE in 1983 providing for permanent disposal of its spent nuclear fuel in exchange for agreed payments fixed in the Standard Contract at particular amounts. On January 28, 2004, SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of the Standard Contract, because as of the date of filing, the federal government had accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government’s breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. On January 9, 2006, SCE&G and Santee Cooper accepted a settlement from DOE which requires the payment by DOE of $9 million to the plaintiffs. The payment is to reimburse the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. SCE&G will record its portion ($6 million) of the settlement as a reduction to its fuel costs. As a result, most of the credit will be passed through to its customers through the fuel clause component of its retail electric rates. The settlement also provides for the plaintiffs to submit an annual application to DOE for the reimbursement of certain costs incurred subsequent to July 31, 2005. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through dry cask storage or other technology as it becomes available.

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Gas Distribution

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

Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $17.7 million and $10.5 million at December 31, 2005 and 2004, respectively. The deferral includes the estimated costs associated with the following matters.

·   SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005, SCE&G has spent $21.5 million to remediate the Calhoun Park site, and expects to spend an additional $0.3 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

·   SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by DHEC. The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of December 31, 2005, SCE&G has spent $4.5 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped by it to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost arising from this matter is expected to be recoverable through rates.

PSNC Energy is responsible for environmental cleanup 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 $7.4 million, which reflects its estimated remaining liability at December 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are $3.1 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

REGULATORY MATTERS

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

South Carolina Electric & Gas Company

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

See earlier discussion of increase in retail electric and gas base rates during 2005 in Liquidity and Capital Resources.

In February 2005, the Natural Gas Stabilization Act of 2005 (Stabilization Act) became law in South Carolina. The Stabilization Act 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.

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Synthetic Fuel

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits.

The aggregate investment in these partnerships as of December 31, 2005 is $3.9 million, and through December 31, 2005, they have generated and passed through to SCE&G $188.3 million in tax credits. In a January 2005 order, the SCPSC approved SCE&G’s request to apply these tax credits, net of partnership losses and other expenses, to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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

Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. The synthetic fuel tax credit program expires at the end of 2007.

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

While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. However, SCE&G’s analysis indicates that the synthetic fuel tax credits recorded in 2005 should not be impacted by the phase-out calculation. During 2006 and subject to continuing review of the estimated benchmark range and reference price of oil, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company’s ability to earn and utilize synthetic fuel tax credits in the future. However, the price volatility resulting from the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits in 2006 and 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

If it is determined that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of December 31, 2005, remaining unrecovered costs, based on management’s recording of accelerated deprecation and related tax benefits on its assumption that 2005’s credits will not be subjected to the phase-out provisions, were $89.2 million.

Finally, Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance services for a non-affiliated synthetic fuel production facility. Should synthetic fuel tax credit availability be curtailed under the above phase-out provisions, the level of payment Primesouth receives for these services could be adversely impacted.

Public Service Company of North Carolina, Incorporated

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

The U. S. Congress passed the Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directing the U. S. Department of Transportation (DOT) to establish a pipeline integrity management rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy’s approximately 720 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 110 miles are located within these areas. Fifty percent of these miles of pipeline must be assessed by December 2007, and the remainder by December 2012. Depending on the assessment method used, PSNC Energy will be required to reinspect these same miles of pipeline every five to seven years. Though cost estimates for this project were developed using various assumptions, each of which are subject to imprecision, PSNC Energy currently estimates the total cost to be $8 million for the initial assessments and any subsequent remediation required through December 2012. Effective November 1, 2004 the NCUC authorized the Company to defer for subsequent rate consideration certain expenses incurred to comply with DOT’s pipeline integrity management requirements.

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South Carolina Pipeline Corporation

SCPC has approximately 51 miles of transmission line that are covered by the Integrity Management Rule of the Pipeline Safety Act. Though cost estimates for this project were developed using various assumptions, each of which are subject to imprecision, SCPC currently estimates the total cost to be $10 million for the initial assessments and any subsequent remediation required through December 2012.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Utility Regulation

SCANA’s regulated utilities are subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” which require them to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected. See Note 1 to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2005, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $2.3 billion and $552 million, respectively.

Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of the Company’s utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to each customer since the date of the last reading of their respective meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2005 and 2004, accounts receivable included unbilled revenues of $280.9 million and $213.0 million, respectively, compared to total revenues for 2005 and 2004 of $4.8 billion and $3.9 billion, respectively.

Provisions for Bad Debts and Allowances for Doubtful Accounts

As of each balance sheet date, the Company evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of expected write-offs. These estimates are based on, among other things, comparisons of the relative age of accounts, assigned credit ratings for commercial and industrial accounts, and consideration of actual write-off history. The distribution segments of the Company’s regulated utilities have established write-off histories and regulated service areas that enable the utilities to reliably estimate their respective provisions for bad debts. The Company’s Retail Gas Marketing segment operates in Georgia’s deregulated natural gas market. As such, estimation of the provision for bad debts related to this segment is subject to greater imprecision.

Nuclear Decommissioning

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

44

SCE&G’s share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals $357.3 million, stated in 1999 dollars. This estimate is based on a decommissioning study completed in 2000 which has not yet been updated to incorporate the 20-year license extension for Summer Station received in 2004. SCE&G expects to complete a new decommissioning study in 2006. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the NRC under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.

Under SCE&G’s method of funding decommissioning costs, funds collected through rates are invested in insurance policies on the lives of certain Company personnel. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by SCE&G to an external trust fund. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

Accounting for Pensions and Other Postretirement Benefits

The Company follows SFAS 87, “Employers’ Accounting for Pensions,” in accounting for its defined benefit pension plan. The Company’s plan is fully funded and as such, net pension income is reflected in the financial statements (see Results of Operations). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension income of $18.1 million recorded in 2005 reflects the use of a 5.75% discount rate and an assumed 9.25% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.5% in 2005 would have increased the Company’s pension income by approximately $0.4 million. Had the assumed long-term rate of return on assets been 9.0%, the Company’s pension income for 2005 would have been reduced by approximately $2.1 million.

 In determining the appropriate discount rate for 2005, the Company considered the market indices of high-quality long-term fixed income securities and selected the discount rate of 5.75% as being within a reasonable range of interest rates for obligations rated Aa by Moody’s as of January 1, 2005. For 2006, the discount rate to be used will be 5.6%, which was derived using a cash flow matching technique which the Company believes is preferable. The same discount rates were also selected for determination of other postemployment benefits costs discussed below.

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

The Company determines the fair value of substantially all of its pension assets utilizing market quotes rather than utilizing any calculated values, “market related” values or other modeling techniques.

In developing the expected long-term rate of return assumptions, the Company evaluates input from actuaries and from pension fund investment consultants. Such consultants’ 2005 review of the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 9.8%, 11.6%, 11.6% and 12.3%, respectively, all of which have been in excess of related broad indices. The 2005 expected long-term rate of return of 9.25% was based on a target asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2006, the expected rate of return will be 9.0%.

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

Similar to its pension accounting, the Company follows SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to 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 5.75% and recorded a net SFAS 106 cost of $17.0 million for 2005. Had the selected discount rate been 5.50%, the expense for 2005 would have been $0.2 million higher.

45

Asset Retirement Obligations

SFAS 143, together with FIN 47, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates primarily to the Company’s regulated utility operations, adoption of SFAS 143 and FIN 47 had no significant impact on results of operations. As of December 31, 2005, the Company has recorded an ARO of approximately $132 million for nuclear plant decommissioning (as discussed above) and an ARO of approximately $191 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines, which was recorded under FIN 47. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. Changes in these estimates will be recorded over time, but as stated above, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s regulated utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Financing

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

Claims and Litigation

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

46

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

The tables below provide information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the 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 and related maturities. Fair values for debt and swaps represent quoted market prices.

	Expected Maturity Date
December 31, 2005 Millions of dollars	2006	2007	2008	2009	2010	Thereafter	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	174.4	68.6	158.6	143.6	43.6	2,524.6	3,113.4	3,108.8
Average Fixed Interest Rate (%)	8.50	6.96	6.13	6.39	6.99	6.14	6.47
Variable Rate ($)			100.0				100.0	100.0
Average Variable Interest Rate (%)			4.56				4.56
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	28.2	3.2	3.2	3.2	6.4	47.4	0.1
Average Pay Interest Rate (%)	7.72	7.97	7.72	7.72	7.72	7.72	7.87
Average Receive Interest Rate (%)	8.75	7.11	8.75	8.75	8.75	8.75	7.77

	Expected Maturity Date
December 31, 2004 Millions of dollars	2005	2006	2007	2008	2009	Thereafter	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	193.6	174.4	68.6	158.6	143.6	2,532.8	3,271.6	3,404.5
Average Fixed Interest Rate (%)	7.39	8.50	6.96	8.12	8.21	6.24	6.62
Variable Rate ($)		200.0					200.0	200.0
Average Variable Interest Rate (%)		2.73					2.73
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	28.2	118.2	3.2	119.6	275.6	4.2
Average Pay Interest Rate (%)	5.74	5.74	6.04	4.73	5.74	4.46	4.78
Average Receive Interest Rate (%)	8.75	8.75	7.11	5.89	8.75	6.45	6.36

 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 table excludes approximately $97 million and $94 million in long-term debt as of December 31, 2005 and 2004, respectively, which amounts do not have a stated interest rate associated with them.

In December 2005, the Company entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, the fair value of this treasury lock agreement was a loss of approximately $3.8 million.

47

Commodity Price Risk

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

Expected Maturity:
				Options
	Futures Contracts			Purchased Call	Purchased Put	Sold Put
2006	Long ($)	Short ($)		(Long) ($)	(Short) ($)	(Long) ($)
Settlement Price (a)	11.07	11.21	Strike Price (a)	9.65	-	7.13
Contract Amount	22.7	8.2	Contract Amount	1.0	-	1.0
Fair Value	23.7	9.0	Fair Value	-	-	-
2007
Settlement Price (a)	11.61	-	Strike Price (a)	-	-	-
Contract Amount	1.0	-	Contract Amount	-	-	-
Fair Value	1.0	-	Fair Value	-	-	-
(a) Weighted average

Swaps	2006	2007
Commodity Swaps:
Pay fixed/receive variable ($)	85.3	8.4
Average pay rate (a)	11.254	8.955
Average received rate (a)	11.061	10.504
Pay variable/receive fixed ($)	9.2	-
Average pay rate (a)	11.253	-
Average received rate (a)	8.665	-
Basis Swaps:
Pay variable/receive variable ($)	137.5	-
Average pay rate (a)	10.681	-
Average received rate (a)	10.660	-
(a) Weighted average

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

The NYMEX futures information above includes those financial positions of Energy Marketing, SCPC and PSNC Energy. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. SCPC’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. In a July 2005 order, in connection with SCPC’s 2005 annual prudency review, the SCPSC determined that SCPC’s gas costs, including all hedging activities, were reasonable and prudently incurred during the 12-month review period ended December 31, 2004.

PSNC Energy utilizes NYMEX futures, options and swaps to hedge gas purchasing activities. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over or under recovery of gas costs. In a September 2005 order, in connection with PSNC Energy’s 2005 annual prudency review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2005.

48

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

SCANA Corporation:

We have audited the accompanying Consolidated Balance Sheets of SCANA Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related Consolidated Statements of Income, Changes in Common Equity and Comprehensive Income and of Cash Flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SCANA Corporation and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, 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, 2006, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Columbia, South Carolina

March 1, 2006

49

SCANA Corporation

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2005			2004
Assets
Utility Plant In Service	$	8,999		$	8,373
Accumulated Depreciation and Amortization		(2,698	)		(2,315	)
		6,301			6,058
Construction Work in Progress		175			432
Nuclear Fuel, Net of Accumulated Amortization		28			42
Acquisition Adjustments		230			230
Utility Plant, Net		6,734			6,762
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $62 and $50		108			104
Assets held in trust, net-nuclear decommissioning		52			49
Other investments		87			83
Nonutility Property and Investments, Net		247			236
Current Assets:
Cash and cash equivalents		62			119
Receivables, net of allowance for uncollectible accounts of $25 and $16		881			712
Receivables-affiliated companies		24			19
Inventories (at average cost):
Fuel		284			191
Materials and supplies		79			70
Emission allowances		54			9
Prepayments and other		54			52
Deferred income taxes		26			10
Total Current Assets		1,464			1,182
Deferred Debits:
Environmental		28			18
Pension asset, net		303			285
Other regulatory assets		589			372
Other		154			151
Total Deferred Debits		1,074			826
Total	$	9,519		$	9,006

50

December 31, (Millions of dollars)	2005		2004
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,677	$	2,451
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,783		2,557
Preferred Stock, Net (Subject to purchase or sinking funds)		8		9
Long-Term Debt, Net		2,948		3,186
Total Capitalization		5,739		5,752
Current Liabilities:
Short-term borrowings		427		211
Current portion of long-term debt		188		204
Accounts payable		471		381
Accounts payable-affiliated companies		26		18
Customer deposits and customer prepayments		70		66
Taxes accrued		112		132
Interest accrued		52		51
Dividends declared		47		43
Other		107		78
Total Current Liabilities		1,500		1,184
Deferred Credits:
Deferred income taxes, net		940		895
Deferred investment tax credits		121		121
Asset retirement obligations		322		124
Non-legal asset retirement obligations		488		450
Postretirement benefits		148		142
Other regulatory liabilities		117		209
Other		144		129
Total Deferred Credits		2,280		2,070
Commitments and Contingencies (Note 10)		-		-
Total	$	9,519	$	9,006

See Notes to Consolidated Financial Statements.

51

SCANA Corporation

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, (Millions of dollars, except per share amounts)	2005			2004			2003
Operating Revenues:
Electric	$	1,909		$	1,688		$	1,466
Gas-regulated		1,405			1,126			1,086
Gas-nonregulated		1,463			1,071			864
Total Operating Revenues		4,777			3,885			3,416
Operating Expenses:
Fuel used in electric generation		618			467			334
Purchased power		37			51			64
Gas purchased for resale		2,399			1,753			1,532
Other operation and maintenance		632			608			558
Depreciation and amortization		510			265			238
Other taxes		145			145			139
Total Operating Expenses		4,341			3,289			2,865
Operating Income		436			596			551
Other Income (Expense):
Other revenues		248			181			167
Other expenses		(200	)		(160	)		(123	)
Gain (loss) on sale of investments and assets		9			(20	)		61
Investment impairments		-			(27	)		(53	)
Preferred dividends of subsidiary		(7	)		(7	)		(9	)
Allowance for equity funds used during construction		-			16			19
Interest charges, net of allowance for borrowed funds used during construction   of $3, $10 and $11		(212	)		(202	)		(200	)
Total Other Expense		(162	)		(219	)		(138	)
Income Before Income Taxes (Benefit) and Earnings (Losses) from   Equity Method Investments		274			377			413
Income Tax Expense (Benefit)		(118	)		123			135
Income Before Earnings (Losses) from Equity Method Investments		392			254			278
Earnings (Losses) from Equity Method Investments		(72	)		3			4
Net Income	$	320		$	257		$	282
Basic and Diluted Earnings Per Share of Common Stock	$	2.81		$	2.30		$	2.54
Weighted Average Common Shares Outstanding (Millions)		113.8			111.6			110.8

See Notes to Consolidated Financial Statements.

52

SCANA Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2005			2004			2003
Cash Flows From Operating Activities:
Net Income	$	320		$	257		$	282
Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities:
Losses (earnings) from equity method investments		72			(3	)		(4	)
Depreciation and amortization		518			274			249
Amortization of nuclear fuel		18			22			21
(Gain) loss on sale of assets and investments		(9	)		20			(61	)
Impairment of investments		-			27			53
Hedging activities		4			11			4
Allowance for equity funds used during construction		-			(16	)		(19	)
Carrying cost recovery		(11	)		-			-
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		(174	)		(225	)		(60	)
Inventories		(188	)		(90	)		(8	)
Prepayments and other		-			(2	)		4
Pension asset		(17	)		(14	)		(5	)
Other regulatory assets		(28	)		(17	)		-
Deferred income taxes, net		25			74			38
Regulatory liabilities		(159	)		48			53
Postretirement benefits obligations		6			7			4
Accounts payable		79			91			(69	)
Taxes accrued		(20	)		23			6
Interest accrued		1			(4	)		3
Changes in fuel adjustment clauses		(7	)		(3	)		23
Changes in other assets		(17	)		22			(6	)
Changes in other liabilities		54			77			37
Net Cash Provided From Operating Activities		467			579			545
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(366	)		(478	)		(668	)
Proceeds from sale of assets and investments		10			68			74
Nonutility property additions		(19	)		(23	)		(12	)
Investments		(18	)		(20	)		(22	)
Net Cash Used For Investing Activities		(393	)		(453	)		(628	)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock		84			65			6
Proceeds from issuance of debt		221			136			978
Repayments of debt		(470	)		(169	)		(856	)
Redemption/repurchase of equity securities		(1	)		(4	)		(61	)
Dividends on equity securities		(181	)		(168	)		(158	)
Short-term borrowings, net		216			16			(14	)
Net Cash Used For Financing Activities		(131	)		(124	)		(105	)
Net Increase (Decrease) in Cash and Cash Equivalents		(57	)		2			(188	)
Cash and Cash Equivalents, January 1		119			117			305
Cash and Cash Equivalents, December 31	$	62		$	119		$	117
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $3, $10 and $11)	$	213		$	206		$	197
-Income taxes		58			24			77
Noncash Investing and Financing Activities:
Unrealized gain (loss) on securities available for sale, net of tax		-			(2	)		2
Accrued construction expenditures		36			49			34

See Notes to Consolidated Financial Statements.

53

SCANA Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME 

									Accumulated
									Other
	Common Stock					Retained			Comprehensive
	Shares		Amount			Earnings			Income (Loss)			Total
	(Millions)
Balance as of December 31, 2002	111		$1,192			$984			$1			$2,177
Comprehensive Income:
Net Income							282						282
Unrealized gains on securities, net of taxes $1										2			2
Unrealized gains on hedging activities, net of taxes $2										3			3
Total Comprehensive Income							282			5			287
Issuance of Common Stock				6									6
Repurchase of Common Stock				(11	)								(11	)
Dividends Declared on Common Stock							(153	)					(153	)
Balance as of December 31, 2003		111	$	1,187		$	1,113		$	6		$	2,306
Comprehensive Income (Loss):
Net Income							257						257
Unrealized loss on securities, net of taxes $(1)										(2	)		(2	)
Unrealized loss on hedging activities, net of taxes $(4)										(8	)		(8	)
Total Comprehensive Income							257			(10	)		247
Issuance of Common Stock		2		65									65
Repurchase of Common Stock				(4	)								(4	)
Dividends Declared on Common Stock							(163	)					(163	)
Balance as of December 31, 2004		113	$	1,248		$	1,207		$	(4	)	$	2,451
Comprehensive Income (Loss):
Net Income							320						320
Unrealized gains on hedging activities, net of taxes $1										1			1
Minimum pension liability adjustment, net of taxes $(1)										(1	)		(1	)
Total Comprehensive Income							320			-			320
Issuance of Common Stock		2		84									84
Dividends Declared on Common Stock							(178	)					(178	)
Balance as of December 31, 2005		115	$	1,332		$	1,349		$	(4	)	$	2,677

See Notes to Consolidated Financial Statements.

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.Organization and Principles of Consolidation

SCANA Corporation (SCANA, and together with its consolidated subsidiaries, the Company), a South Carolina corporation, is a holding company. The Company, through wholly owned subsidiaries, is engaged 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 is also engaged in other energy-related businesses and provides fiber optic communications in South Carolina.

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

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

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

B.Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of SFAS 71, which requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded as of December 31, 2005, approximately $617 million and $605 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	December 31,
	2005			2004
	Millions of dollars
Accumulated deferred income taxes, net	$	138		$	126
Under-collections-electric fuel and gas cost adjustment clauses, net		41			9
Deferred purchased power costs		17			26
Deferred environmental remediation costs		28			18
Asset retirement obligations and related funding		250			76
Non-legal asset retirement obligations		(488	)		(450	)
Deferred synthetic fuel tax benefits, net		-			(97	)
Storm damage reserve		(38	)		(33	)
Franchise agreements		56			58
Deferred regional transmission organization costs		11			14
Other		(3	)		(16	)
Total	$	12		$	(269	)

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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 and gas cost adjustment clauses, net, represent amounts under-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings. See Note 1F.

Deferred purchased power costs-represents costs that were necessitated by outages at two of SCE&G’s base load generating plants in winter 2000-2001. The SCPSC approved recovery of these costs in base rates over a three year period beginning January 2005.

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G are being recovered through rates, of which approximately $17.7 million remain to be recovered. A portion of the costs incurred at sites owned by PSNC Energy has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered by PSNC Energy through rates are approximately $3.1 million. Management believes that these costs and the estimated remaining costs of approximately $7.4 million will be recoverable by PSNC Energy.

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

Non-legal AROs represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

Deferred synthetic fuel tax benefits, net represented the deferral of partnership losses and other expenses offset by the tax benefits of those losses and expenses and accumulated synthetic fuel tax credits associated with SCE&G’s investment in two partnerships involved in converting coal to synthetic fuel. In 2005, under an accounting plan approved by the SCPSC, any tax credits generated from synthetic fuel produced by the partnerships and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership losses and other expenses, are being used to offset the capital costs of constructing the back-up dam at Lake Murray. See Note 2.

The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. During the year ended December 31, 2005, no significant amounts were drawn from this reserve account. During the year ended December 31, 2004, approximately $10.9 million was drawn from this reserve account.

Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are being amortized through cost of service rates over approximately 15 years.

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

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The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by a state commission. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C. System of Accounts

The accounting records of the Company’s regulated subsidiaries are maintained in accordance with the Uniform System of Accounts prescribed by FERC and as adopted by state commissions.

D.Utility Plant and Major Maintenance

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

SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G’s portion of Summer Station was $1.0 billion as of December 31, 2005 and 2004 (including amounts related to ARO). Accumulated depreciation associated with SCE&G’s share of Summer Station was $478.7 million and $463.7 million as of December 31, 2005 and 2004, respectively (including amounts related to ARO). SCE&G’s share of the direct expenses associated with operating Summer Station is included in “Other operation and maintenance” expenses and totaled $76.3 million, $74.5 million and $74.7 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, SCE&G is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2005, SCE&G incurred $4.9 million for turbine maintenance. The remaining $3.6 million is in a regulatory liability account on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage upon completion of the preceding outage. SCE&G accrued $0.8 million per month from January 2004 through June 2005 for its portion of the outage in April 2005 and is accruing $1.0 million per month for its portion of the outage scheduled for October 2006. Total costs for the 2005 outage were $22.3 million, of which SCE&G was responsible for $14.9 million. Total costs for the planned outage in 2006 are estimated to be $25.7 million, of which SCE&G will be responsible for $17.2 million. As of December 31, 2005 and 2004, SCE&G had accrued $5.7 million and $9.9 million, respectively.

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E. Allowance for Funds Used During Construction (AFC)

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using composite rates of 4.9%, 6.9% and 8.1% for 2005, 2004 and 2003, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred.

F.Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered, but not yet billed. Unbilled revenues totaled $280.9 million and $213.0 million as of December 31, 2005 and 2004, respectively.

Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. SCE&G had undercollected through the electric fuel cost component $44.1 million and $6.0 million at December 31, 2005 and 2004, respectively, which amounts are included in other regulatory assets.

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the state commission during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 2005 and 2004, SCE&G had undercollected (overcollected) $11.8 million and $(7.8) million, respectively, which amounts are also included in other regulatory assets or liabilities. At December 31, 2005, PSNC Energy had overcollected $(15.1) million, net, which also is included in other regulatory liabilities. At December 31, 2004, PSNC Energy had undercollected $10.8 million, net, which is included in other regulatory assets.

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

G.Depreciation and Amortization

Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property.

The composite weighted average depreciation rates for utility plant assets were as follows:

	2005			2004			2003
SCE&G		3.20	%		2.99	%		3.02	%
GENCO		2.66	%		2.66	%		2.66	%
SCPC		2.01	%		2.04	%		2.13	%
PSNC Energy		3.77	%		3.87	%		4.05	%
Aggregate of Above		3.20	%		3.04	%		3.10	%

For SCE&G, the above rates reflect higher depreciation rates approved by the SCPSC in connection with electric and gas rate cases effective January 2005 and November 2005, respectively. See Note 2.

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

The Company considers amounts categorized by FERC as “acquisition adjustments” to be goodwill as defined in SFAS 142, “Goodwill and Other Intangible Assets,” and has ceased amortization of such amounts. These amounts are related to acquisition adjustments of approximately $466 million ($210 million net of accumulated amortization) million recorded on the books of PSNC Energy (Gas Distribution segment) and approximately $40 million ($20 million net of accumulated amortization) recorded on the books of SCPC (Gas Transmission segment). In accordance with SFAS 142, the Company performs an annual impairment evaluation of its investment in PSNC Energy and SCPC. These calculations have indicated no need for write-downs of acquisition adjustments since the write-down taken by PSNC Energy upon initial adoption of SFAS 142 in 2002. Should a write-down be required in the future, such a charge would be treated as an operating expense.

H.Nuclear Decommissioning

SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.

Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million in each of 2005, 2004 and 2003) are invested in insurance policies on the lives of certain Company personnel. Amounts collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by SCE&G to an external trust fund. The trusteed asset balance reflects the net cash surrender value of the insurance policies held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

I.Income and Other Taxes

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

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

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

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

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K. Environmental

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

L. Cash and Cash Equivalents

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

M.Commodity Derivatives

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

SCPC’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC’s hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over or under recovery of gas costs.

N.New Accounting Standards

SFAS 154, “Accounting Changes and Error Corrections,” was issued in June 2005. It requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

Effective December 15, 2005, the Company adopted FIN 47, which was issued to clarify the term “conditional asset retirement” as used in SFAS 143. It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation 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.

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The following table presents conditional asset retirement obligations and related assets as recorded in the Consolidated Balance Sheet as of December 31, 2005, and the proforma amounts that would have been recorded as of December 31, 2004 and 2003 had FIN 47 been adopted at the beginning of 2003.

Millions of dollars	December 31,			December 31,			December 31,
	2005			2004			2003
	Actual			Proforma			Proforma
Assets:
Within utility plant	$	45		$	45		$	45
Within accumulated depreciation		(23	)		(22	)		(21	)
Within other regulatory assets		169			159			149
Total	$	191		$	182		$	173
Liabilities:
Asset retirement obligation	$	191		$	182		$	173

Due to the regulated nature of the business for which conditional asset retirement obligations were recognized, the adoption of FIN 47 did not have a material impact on the Company’s results of operations, cash flows or financial position for the year ended December 31, 2005. Proforma net income and earnings per share for the periods prior to the adoption of FIN 47 would not differ from amounts actually recorded during these periods. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:

Millions of dollars	2005		2004
Beginning balance	$	124	$	117
Accretion expense		7		7
Adoption of FIN 47		191		-
Ending Balance	$	322	$	124

SFAS 123 (revised 2004),“Share-Based Payment,” was issued in December 2004 and will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB 25, “Accounting for Stock Issued to Employees.” The Company plans to adopt SFAS 123(R) in the first quarter of 2006 and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

O.Equity Compensation Plan

Under the SCANA Corporation Long-Term Equity Compensation Plan (the Plan), certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity-based compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, “Accounting for Stock Issued to Employees,” and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, “Accounting for Stock-Based Compensation,” and SFAS 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.”

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Options, all of which were granted prior to 2005, and all of which were fully vested as of December 31, 2005, were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense has been recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings per share would have been as follows:

	2005		2004		2003
Net income-as reported (millions)	$	319.5	$	257.1	$	282.0
Net income-pro forma (millions)		319.3		256.0		280.3
Basic and diluted earnings per share-as reported		2.81		2.30		2.54
Basic and diluted earnings per share-pro forma		2.80		2.29		2.52

The Company also grants other forms of equity-based compensation (performance awards) to certain employees. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $3.6 million, $12.9 million and $8.9 million for the years ended December 31, 2005, 2004 and 2003, respectively.

P. Earnings Per Share

Earnings per share amounts have been computed in accordance with SFAS 128, “Earnings Per Share.” Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the period, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has no securities that would have an antidilutive effect on earnings per share.

Q. Transactions with Affiliates

The Company received cash distributions from equity investees of approximately $7.1 million, $7.3 million and $7.4 million during 2005, 2004 and 2003, respectively.

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G had recorded as receivables from these affiliated companies approximately $24.6 million and $18.6 million at December 31, 2005 and 2004, respectively. SCE&G had recorded as payables to these affiliated companies approximately $25.3 million and $17.8 million at December 31, 2005 and 2004, respectively. SCE&G purchased approximately $248.1 million, $190.6 million and $145.8 million of synthetic fuel from these affiliated companies in 2005, 2004 and 2003, respectively.

Summarized combined financial information of unconsolidated affiliates as of and for the years ended December 31, 2005, 2004 and 2003, is presented below:

	2005			2004			2003
	Millions of dollars
Current assets	$	61		$	55		$	52
Non-current assets		339			355			371
Current liabilities		56			49			47
Non-current liabilities		186			200			213
Revenues		333			314			271
Gross profit		52			31			35
Income (loss) before income taxes		(33	)		(34	)		(23	)

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R. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

S. Use of Estimates

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

2. RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company

Electric

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of 2.89%, designed to produce additional annual revenues of $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's allowed return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and, beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray Dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

In the January 2005 order, the SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year.  No such additional depreciation was recognized in 2005, 2004 or 2003.

SCE&G's rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. SCE&G's cost of fuel component in effect during 2005 and 2004 was as follows:

Rate Per KWh	Effective Date
$.01678	January-April 2004
$.01821	May-December 2004
$.01764	January-April 2005
$.02256	May-December 2005

Gas

In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69%, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25% and became effective with the first billing cycle in November 2005.

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SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during 2005 and 2004 was as follows:

Rate Per Therm	Effective Date
$.877	January-October 2004
$.903	November 2004-October 2005

In October 2005 the SCPSC approved an increase in SCE&G’s cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general service classes, respectively. These new rates were effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006. Effective in December 2005, the SCPSC approved an increase in the cost of gas component to $1.36159, $1.28648 and $1.26253 per therm for residential, small and medium general service and large general service classes, respectively.

Since January 1, 2006, the SCPSC has approved decreases in SCE&G’s cost of gas components from $1.36159, $1.28648 and $1.26253 to $1.22695, $1.15184 and $1.12789 per therm for residential, small and medium general service and large general service classes, respectively, effective February 14, 2006.

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

Public Service Company of North Carolina, Incorporated

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

PSNC Energy's benchmark cost of gas in effect during 2005 and 2004 was as follows:

Rate Per Therm	Effective Date
$.600	January-September 2004
$.675	October-November 2004
$.825	December 2004-January 2005
$.725	February-July 2005
$.825	August-September 2005
$1.10	October 2005
$1.275	November-December 2005

Since January 1, 2006 the NCUC has approved two decreases in PSNC Energy’s benchmark cost of gas, from $1.075 per therm to $.825 per therm for service rendered on and after March 1, 2006.

In November 2005, the NCUC authorized an amendment to PSNC Energy’s Rider D rate mechanism allowing recovery of certain uncollectible expenses related to gas cost. This change was effective December 1, 2005.

In September 2005, in connection with the Company’s 2005 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2005. The NCUC also authorized new rate decrements, effective October 1, 2005, to refund over-collections of certain gas costs included in deferred accounts.

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A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In September 2005 the NCUC approved PSNC Energy’s request for disbursement of up to $1.1 million from the expansion fund to extend natural gas service to Louisburg, North Carolina. The project is expected to be completed in 2006.

In March 2005 PSNC Energy refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers.

Effective November 1, 2004 the NCUC authorized PSNC Energy to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation's Pipeline Integrity Management requirements.

South Carolina Pipeline Corporation

SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In a July 2005 order, the SCPSC found that for the period January through December 2004 SCPC's gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff.

3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

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

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

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

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

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Changes in Benefit Obligation

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.

	Retirement Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
	Millions of dollars
Benefit obligation, January 1	$	669.5		$	619.9		$	197.5		$	188.4
Service cost		12.2			11.1			3.5			3.3
Interest cost		38.3			37.4			10.7			11.4
Plan participants' contributions		-			-			2.3			1.1
Plan amendments		-			8.0			(0.3	)		4.7
Actuarial loss		27.1			24.1			1.5			1.2
Benefits paid		(35.6	)		(31.0	)		(13.1	)		(12.6	)
Benefit obligation, December 31	$	711.5		$	669.5		$	202.1		$	197.5

The accumulated benefit obligation for retirement benefits at the end of 2005 and 2004 was $664.4 million and $635.8 million, respectively. These accumulated retirement benefit obligations differ from the projected retirement benefit obligations above in that they reflect no assumptions about future compensation levels.

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

	2005			2004
Annual discount rate used to determine benefit obligations		5.60	%		5.75	%
Assumed annual rate of future salary increases for projected benefit obligation		4.00	%		4.00	%

A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5.0% for 2012 and to remain at that level thereafter. The effects of a one percentage point increase or decrease on accumulated other postretirement benefit obligation for health care benefits are as follows:

	1% Increase		1% Decrease
	Millions of dollars
Effect on postretirement benefit obligation	$	3.5	$	(3.1	)

In May 2004, the Financial Accounting Standards Board issued Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act” (“FSP 106-2”). FSP 106-2 provides definitive guidance on the recognition of the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 and related disclosure requirements for employers that sponsor prescription drug benefit plans for retirees. In the quarter beginning July 1, 2004 the Company adopted FSP 106-2. The expected subsidy reduced the accumulated postretirement benefit obligation (APBO) as of July 1, 2004 by $3.7 million, and net periodic cost for 2004 by $0.2 million, as compared to the amount calculated without considering the effects of the subsidy.

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Changes in Plan Assets

	Retirement Benefits
	2005			2004
	Millions of dollars
Fair value of plan assets, January 1	$	846.7		$	787.7
Actual return on plan assets		43.2			90.0
Benefits paid		(35.6	)		(31.0	)
Fair value of plan assets, December 31	$	854.3		$	846.7

At the end of 2005 and 2004, the fair value of plan assets for the pension plan exceeded both the projected benefit obligation and the accumulated benefit obligation discussed above. Since the accumulated benefit obligation is less than the fair value of plan assets, there is no adjustment to other comprehensive income.

Funded Status of Plans

	Retirement Benefits				Other Postretirement Benefits
	2005		2004		2005			2004
	Millions of dollars
Funded status, December 31	$	142.9	$	177.2	$	(202.1	)	$	(197.5	)
Unrecognized actuarial loss		88.4		28.2		44.4			44.2
Unrecognized prior service cost		71.3		78.3		5.2			6.4
Unrecognized net transition obligation		0.6		1.4		4.3			5.0
Net asset (liability) recognized in consolidated balance sheet	$	303.2	$	285.1	$	(148.2	)	$	(141.9	)

In connection with the joint ownership of Summer Station, as of December 31, 2005 and 2004, the Company recorded within deferred credits a $10.2 million and $9.7 million obligation, respectively, to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the pension plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. As of December 31, 2005 and 2004, the Company also recorded within deferred debits a $7.1 million and $6.8 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.

Expected Cash Flows

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

		Other Postretirement Benefits*
Expected Benefit Payments	Pension Benefits	Excluding Medicare Subsidy	Including Medicare Subsidy
	Millions of dollars
2006	$35.9	$11.3	$10.9
2007	37.7	12.1	11.7
2008	39.6	12.8	12.3
2009	41.6	13.2	12.7
2010	43.6	13.7	13.2
2011-2015	253.5	72.8	70.6

*Net of participant contributions

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Net Periodic Cost

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

Components of Net Periodic Benefit Cost (Income)

	Retirement Benefits									Other Postretirement Benefits
	2005			2004			2003			2005		2004		2003
	Millions of dollars
Service cost	$	12.2		$	11.1		$	9.5		$	3.5	$	3.3	$	2.7
Interest cost		38.3			37.4			36.7			10.7		11.4		11.4
Expected return on assets		(76.3	)		(71.0	)		(59.9	)		n/a		n/a		n/a
Prior service cost amortization		6.9			6.6			6.3			0.8		1.4		0.9
Amortization of actuarial (gain) loss		-			-			1.6			1.2		1.9		1.5
Transition amount amortization		0.8			0.8			0.8			0.8		0.8		0.8
Net periodic benefit (income) cost	$	(18.1	)	$	(15.1	)	$	(5.0	)	$	17.0	$	18.8	$	17.3

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

	Retirement Benefits									Other Postretirement Benefits
	2005			2004			2003			2005			2004			2003
Discount rate		5.75	%		6.00	%		6.50	%		5.75	%		6.00	%		6.50	%
Expected return on plan assets		9.25	%		9.25	%		9.25	%		n/a			n/a			n/a
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%
Health care cost trend rate		n/a			n/a			n/a			9.00	%		9.50	%		10.00	%
Ultimate health care cost trend rate		n/a			n/a			n/a			5.00	%		5.00	%		5.00	%
Year achieved		n/a			n/a			n/a			2011			2011			2011
Measurement date		Jan 1			Jan 1			Jan 1			Jan 1			Jan 1			Jan 1

The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $250,000.

Pension Plan Contributions

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

Pension Plan Asset Allocations

The Company's pension plan asset allocation at December 31, 2005 and 2004 and the target allocations for 2006 are as follows:

	Target Allocation			Percentage of Plan Assets At December 31,
Asset Category	2006			2005			2004
Equity Securities		70	%		72	%		72	%
Debt Securities		30	%		28	%		28	%

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

In developing the expected long-term rate of return assumptions, management evaluates the pension plan's historical cumulative actual returns over several periods, all of which returns have been in excess of related broad indices. The expected long-term rate of return of 9.25% assumes an asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2006, the expected rate of return will be 9.0%.

Long-Term Equity Compensation Plan

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

A summary of activity related to nonqualified stock options follows:

	Number of Options			Weighted Average Exercise Price
Outstanding-December 31, 2002		1,717,910		$	27.39
Exercised		(203,052	)		27.41
Forfeited		(21,173	)		27.50
Outstanding-December 31, 2003		1,493,685			27.39
Exercised		(751,997	)		26.28
Forfeited		(11,241	)		27.52
Outstanding-December 31, 2004		730,447			27.49
Exercised		(297,477	)		27.40
Forfeited		-			-
Outstanding-December 31, 2005		432,970			27.53

No options have been granted since 2002, and as of December 31, 2005, all options had vested. The options expire ten years after the grant date. At December 31, 2005, all outstanding options could be exercised at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 6.1 years.

At December 31, 2004 and 2003 exercisable options totaled 388,487 at a weighted average exercise price of $27.42 and 648,392 at a weighted average exercise price of $27.19, respectively.

The Company also grants other forms of equity based compensation to certain employees. These performance awards consist of hypothetical share grants which vest and become payable upon the attainment of specified performance metrics, and compensation is recorded under APB 25. These awards may be settled in shares of Company stock or in cash at the Company's determination. Total expense recorded for these awards was approximately $3.6 million, $12.9 million and $8.9 million in 2005, 2004 and 2003, respectively.

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4. LONG-TERM DEBT

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

			December 31,
	Weighted-Average Interest Rate	Maturity Date	2005	2004
			Millions of dollars
Medium-Term Notes (unsecured)(a)	6.29%	2007-2012	$940	$1,040
First Mortgage Bonds (secured)	5.98%	2009-2035	1,550	1,700
First & Refunding Mortgage Bonds (secured)	9.00%	2006	131	131
GENCO Notes (secured)	5.97%	2011-2024	127	130
Industrial and Pollution Control Bonds	5.24%	2012-2032	156	156
Senior Debentures(b)	7.50%	2012-2026	122	126
Fair value of interest rate swaps(c)			25	32
Other		2006-2014	107	94
Total debt			3,158	3,409
Current maturities of long-term debt			(188)	(204)
Unamortized Discount			(22)	(19)
Total long-term debt, net			$2,948	$3,186

(a) In 2005, includes $100.0 million of variable interest debt and $25.0 million of fixed rate debt hedged by a variable interest rate swap.

(b) In 2005, includes $22.4 million of fixed rate debt hedged by variable interest rate swaps.

(c) In 2005, includes $24.7 million representing unamortized payments received to terminate previous swaps. See discussion at Note 9.

The annual amounts of long-term debt maturities and sinking fund requirements for the years 2006 through 2010 are summarized as follows:

Year	Amount
	(Millions of dollars)
2006	$	188
2007		78
2008		267
2009		183
2010		50

Approximately $35.5 million of the long-term debt maturing in 2006 relates to a sinking fund requirement, which may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee.

In 2004 and 2005 SCE&G borrowed an aggregate $59 million availableunder an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. Such borrowings are being repaid interest-free over ten years from the initial borrowing. At December 31, 2005 SCE&G had $50.2 million outstanding under the agreement.

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

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5. LINES OF CREDIT AND SHORT-TERM BORROWINGS

Details of lines of credit and short-term borrowings at December 31, 2005 and 2004, are as follows:

	2005			2004
	Millions of dollars
Lines of credit (total and unused)
Committed
Short-term	$	350		$	100
Long-term		650			650
Uncommitted		103	(a)		113	(a)
Bank loans/commercial paper outstanding (270 or fewer days):
SCANA	$	25			-
Weighted average interest rate		4.43	%		-
SCE&G	$	196		$	122
Weighted average interest rate		4.40	%		2.39	%
Fuel Company	$	107		$	31
Weighted average interest rate		4.39	%		2.44	%
PSNC Energy	$	99		$	58
Weighted average interest rate		4.47	%		2.47	%
Total	$	427		$	211
Weighted average interest rate		4.42	%		2.42	%

(a)  SCANA or SCE&G may use $78 million of these lines of credit.

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

Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. All commercial paper borrowings are supported by five-year revolving credit facilities which expire on June 30, 2010.

6. COMMON EQUITY

The Company's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2005 approximately $51 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

Cash dividends on common stock were declared during 2005, 2004 and 2003 at an annual rate per share of $1.56, $1.46 and $1.38, respectively.

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

	Unrealized gains (losses) on securities			Cash flow hedging activities			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (loss)
	Millions of dollars
Balance, December 31, 2002		-		$	1			-		$	1
Other comprehensive income	$	2			3			-			5
Balance, December 31, 2003		2			4			-			6
Other comprehensive loss		(2	)		(8	)		-			(10	)
Balance, December 31, 2004		-			(4	)		-			(4	)
Other comprehensive income (loss)		-			1		$	(1	)		-
Balance, December 31, 2005	$	-		$	(3	)	$	(1	)	$	(4	)

During 2005, no unrealized gains (losses) on securities were reclassified into net income. The Company recognized a gain of $4.0 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2005. The Company also recorded a minimum pension liability during the year ended December 31, 2005.

During 2004, $0.7 million was reclassified from unrealized gains and $12.5 million was reclassified from unrealized losses on securities into net income as a result of the sale of the Company's investments in ITC^DeltaCom, Inc. (ITC^DeltaCom) and the impairment and subsequent sale of the Company's investment in Knology, Inc. (Knology). See Note 9. The Company also recognized a gain of $6.4 million, net of taxes, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2004.

During 2003, no unrealized gains (losses) on securities were reclassified into net income. The Company recognized a gain of $3.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2003.

7. PREFERRED STOCK

Retirements under sinking fund requirements are at par values. The aggregate of the annual amounts of purchase or sinking fund requirements for preferred stock for the years 2006 through 2010 is $2.6 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2005 SCE&G had shares of preferred stock authorized and available for issuance as follows:

Par Value	Authorized	Available for Issuance
$100	1,000,000	-
$ 50	601,613	300,000
$ 25	2,000,000	2,000,000

Preferred Stock (Not subject to purchase or sinking funds)

For each of the three years ended December 31, 2005 SCE&G had outstanding 1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par Cumulative Preferred Stock (not subject to purchase or sinking funds).

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Preferred Stock (Subject to purchase or sinking funds)

Changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2005, 2004 and 2003 are summarized as follows:

	Series
	4.50%, 4.60% (A) & 5.125%	4.60% (B) & 6.00%	Total Shares	Millions of Dollars
Redemption Price	$51.00	$50.50
Balance at December 31, 2002	83,849	116,124	199,973	$10.0
Shares Redeemed-$50 par value	(2,815)	(3,563)	(6,378)	(0.3)
Balance at December 31, 2003	81,034	112,561	193,595	9.7
Shares Redeemed-$50 par value	(2,516)	(6,600)	(9,116)	(0.5)
Balance at December 31, 2004	78,518	105,961	184,479	9.2
Shares Redeemed-$50 par value	(1,475)	(6,600)	(8,075)	(0.4)
Balance at December 31, 2005	77,043	99,361	176,404	$8.8

8. INCOME TAXES

Total income tax expense (benefit) attributable to income for 2005, 2004 and 2003 is as follows:

	2005			2004			2003
	Millions of dollars
Current taxes:
Federal	$	10.2		$	(6.4	)	$	63.1
State		11.1			(5.2	)		12.2
Total current taxes		21.3		$	(11.6	)	$	75.3
Deferred taxes, net:
Federal		1.7			84.5			24.6
State		(6.9	)		5.4			0.3
Total deferred taxes		(5.2	)		89.9			24.9
Investment tax credits:
Deferred-state		5.1			10.0			5.0
Amortization of amounts deferred-state		(1.9	)		(2.1	)		(1.8	)
Amortization of amounts deferred-federal		(3.1	)		(4.0	)		(4.0	)
Total investment tax credits		0.1			3.9			(0.8	)
Synthetic fuel tax credits - federal		(134.2	)		40.5			35.7
Total income tax expense (benefit)	$	(118.0	)	$	122.7		$	135.1

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

	2005			2004			2003
	Millions of dollars
Income	$319.5			$257.1			$282.0
Income tax expense (benefit)		(118.0	)		122.7			135.1
Preferred stock dividends		7.3			7.3			9.1
Total pre-tax income	$	208.8		$	387.1		$	426.2
Income taxes on above at statutory federal income tax rate	$	73.1		$	135.5		$	149.2
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		4.8			5.3			10.2
Synthetic fuel tax credits		(181.9	)		(2.9	)		(2.2	)
Allowance for equity funds used during construction		(0.2	)		(5.5	)		(6.7	)
Deductible dividends-Stock Purchase Savings Plan		(5.9	)		(5.5	)		(4.9	)
Amortization of federal investment tax credits		(3.1	)		(4.0	)		(4.0	)
Non-taxable recovery of Lake Murray Dam project carrying costs		(3.8	)		-			-
Other differences, net		(1.0	)		(0.2	)		(6.5	)
Total income tax expense (benefit)	$	(118.0	)	$	122.7		$	135.1

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $914.5 million at December 31, 2005 and $884.5 million at December 31, 2004 are as follows:

	2005		2004
	Millions of dollars
Deferred tax assets:
Nondeductible reserves	$	84.8	$	84.5
Unamortized investment tax credits		60.0		60.8
Federal alternative minimum tax credit carryforward		44.0		12.3
Deferred compensation		28.5		24.0
Unbilled revenue		12.6		7.0
Other		31.6		28.4
Total deferred tax assets		261.5		217.0
Deferred tax liabilities:
Property, plant and equipment		971.7		937.9
Pension plan benefit income		109.9		101.4
Deferred fuel costs		45.1		20.3
Other		49.3		41.9
Total deferred tax liabilities		1,176.0		1,101.5
Net deferred tax liability	$	914.5	$	884.5

Previously, the Internal Revenue Service had completed and closed examinations of the Company's consolidated federal income tax returns through tax years ending in 2000. In 2005, the Company filed amended federal income tax returns for 1998-2003, which are currently under examination. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on the earnings, cash flows or financial position of the Company. The IRS has also closed the examination of S. C. Coaltech No. 1 L.P., a synthetic fuel partnership in which the Company has an interest, for the 2000 tax year, resulting in that return being accepted as filed. The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed. As discussed in Note 1, certain synthetic fuel tax credits were deferred until 2005, at which time they began to be recognized for financial reporting purposes.

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9. FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2005 and 2004 were as follows:

	2005				2004
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	Millions of dollars
Long-term debt	$	3,136.0	$	3,308.7	$	3,389.5	$	3,699.9
Preferred stock (subject to purchase or sinking funds)		8.2		8.2		9.2		8.5

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

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

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

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

Investments

SCANA and certain of its subsidiaries hold investments, some of which are marketable securities which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable or are otherwise non-marketable, such as life insurance policies. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market prices, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. When indicated, and in accordance with its stated accounting policy, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company's cost basis is other than temporary. When other than temporary declines occur, write- downs are recorded through operations, and new (lower) cost bases are established. Insurance policies are carried at net cash surrender value. The Company also holds investments in several partnerships and joint ventures which are accounted for using the equity method.

Telecommunications Investments

In December 2004, SCH sold its investments in ITC^DeltaCom and Knology resulting in losses of $13.9 million, net of taxes. In 2004, SCH recorded an impairment of its investment in Knology totaling $15.0 million, net of taxes.

In August 2003, Magnolia Holding distributed its holdings in Knology preferred stock to Magnolia Holding's members. As a result, SCH's basis in Magnolia Holding was reduced by, and SCH's basis in Knology was increased by, approximately $6.2 million. During 2003, SCH recorded impairment losses associated with its Knology investment totaling $34.6 million, net of taxes.

In May 2003, the Company's investment in ITC Holding Company was sold. The transaction resulted in the receipt of net after-tax cash proceeds of approximately $48 million and the receipt of the investment interest referred to above in a newly formed entity, Magnolia Holding. A gain, net of tax, of approximately $39 million was recognized upon this transaction.

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Derivatives

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

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

Commodities

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

The Company recognized gains of approximately $4.0 million, $6.4 million and $3.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2005, 2004 and 2003, respectively, including recognized gains on cash flow hedges in which the anticipated transaction did not occur. These amounts were recorded in cost of gas. The Company estimates that most of the December 31, 2005 unrealized loss balance of $2.7 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2006 as an increase to gas cost if market prices remain at current levels. As of December 31, 2005, all of the Company's cash flow hedges will settle by their terms before the end of 2007.

PSNC Energy hedges gas purchasing activities using NYMEX futures, options and swaps. PSNC Energy's tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs.

SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.

Interest Rates

The Company uses interest rate swap agreements to manage interest rate risk. These swaps provide for the Company to pay variable and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap and may replace it with a new swap also designated as a fair value hedge. At December 31, 2005 the estimated fair value of the Company's swaps totaled $0.1 million related to combined notional amounts of $47.4 million.

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

In anticipation of the issuance of debt, the Company also uses interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds on December 2003, the Company paid $3.5 million upon the termination of a forward starting interest rate swap. In December 2005, the Company entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, an unrealized loss on this treasury lock agreement in the amount of $3.8 million has been recorded within other regulatory assets. Any gain or loss on the ultimate settlement of this swap will be amortized over the life of the anticipated debt issuance to which it relates.

10. COMMITMENTS AND CONTINGENCIES

A. Nuclear Insurance

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

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $15.6 million.

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

B. Environmental

South Carolina Electric & Gas Company

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

At SCE&G, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.7 million at December 31, 2005. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005, SCE&G had spent $21.5 million to remediate the Calhoun Park site and expects to spend an additional $0.3 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by DHEC. The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of December 31, 2005, SCE&G has spent $4.5 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped by it to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost arising from this matter is expected to be recoverable through rates.

Public Service Company of North Carolina, Incorporated

PSNC Energy is responsible for environmental cleanup 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 $7.4 million, which reflects its estimated remaining liability at December 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $3.1 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

C. Franchise Agreements

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

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D. Claims and Litigation

In 1999, an unsuccessful bidder for the purchase of certain propane gas assets of the Company filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 21, 2004, the jury issued an adverse verdict on this matter against SCANA for four causes of action for damages totaling $48 million. In accordance with generally accepted accounting principles, in the third quarter of 2004 the Company accrued a liability of $18 million, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.

Post-verdict motions were heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff was ordered to elect a single remedy from the multiple jury awards. In response to the April 2005 election order, the plaintiff elected a remedy with damages totaling $18 million, and the Company placed the funds in escrow with the Clerk of Court to forestall the accrual of post-judgment interest. The funds held in escrow are recorded within prepayments and other assets on the balance sheet and appear as an investing activity in the statement of cash flows. The Company believes its accrued liability is still a reasonable estimate. However, the Company continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

The Company is also defending a claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets. A bench trial on the indemnification was held on January 14, 2005, and on August 9, 2005 an order was entered against the Company in the amount of $2.6 million. On December 2, 2005, the judge vacated this award, and further motions to review his order are pending. The Company has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. Since that time, the plaintiffs have dismissed defendants Duke Energy and Progress Energy and are proceeding against SCE&G only. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may go to trial in 2006. The Company is confident of the propriety of SCE&G’s actions and intend to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

On May 17, 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit Court (the Court). The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than the Company’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Court granted the Company’s motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has appealed. The Company intends to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.

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E.Other Contingency

In 2004 and early 2005, SCANA and certain of its affiliates, like other integrated utilities, were the subject of an investigation by FERC’s Office of Market Oversight and Investigations (OMOI) focusing, among other things, on the relationship between SCE&G’s merchant and transmission functions. These relationships are among those addressed in FERC Order 2004, a primary purpose of which order is to ensure that affiliates of transmission providers have no marketplace advantage over non-affiliated market participants. In connection with that investigation, SCE&G was assessed no monetary damages or penalties; however, under terms of a Settlement and Consent Agreement entered into on April 1, 2005, and approved by FERC order dated April 27, 2005, SCE&G agreed to the implementation of a compliance plan which includes periodic reports to OMOI.

On January 2, 2006, SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgment of SCE&G’s discovery that it may have improperly utilized network transmission services, rather than point-to-point transmission services, for purchases and sales of electricity in violation of SCE&G’s open access transmission tariff and applicable orders under the Federal Power Act that prohibit the use of network transmission service in support of certain “off-system” sales. This acknowledgement was in part the result of SCE&G’s preliminary review of a FERC order issued following its examination of another energy provider in September 2005. Upon further review of that order and a comprehensive analysis, SCE&G has now determined and notified FERC that it did improperly utilize network transmission service in a large number of purchase and sale transactions.

In response to this discovery, SCE&G has notified FERC and has ceased participation in such transactions, has instituted additional self-restrictive procedures as safeguards to ensure full compliance in this area in the future, has committed to certain modifications to its compliance plan, including increased levels of training and monitoring, and is fully cooperating with OMOI to resolve this matter.

As of December 31, 2005, SCE&G has recorded a loss accrual in the amount of approximately $0.8 million based on its estimation of net revenues from these transactions that occurred after the date of the Settlement and Consent Agreement and that might be subject to disgorgement pursuant to FERC orders. However, there remains uncertainty as to what additional actions may be taken by FERC. Potential actions could include further modifications to the compliance plan or other non-monetary remedies. In addition to the disgorgement of profits, such remedies could also include penalties of up to a maximum of $1 million per violation or per day since August 8, 2005, the effective date of the Energy Policy Act of 2005. SCE&G estimates that there were approximately 1,200 of these transactions since August 8, 2005, that, despite the immaterial profits from the transactions, could be deemed in violation of FERC's rule on the use of network transmission service.  In light of SCE&G's self-reporting and other cooperation in the investigation of this matter, SCE&G's belief that no market participants or customers of SCE&G were harmed or disadvantaged by the transactions, and SCE&G’s institution of appropriate safeguards referred to above, SCE&G does not believe that such sanctions are warranted. Nonetheless, SCE&G cannot predict what, if any, actions FERC will take with respect to this matter, and is unable to determine if the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.

F. Operating Lease Commitments

The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2013. Rent expense totaled approximately $13.9 million, $11.8 million and $12.4 million in 2005, 2004 and 2003, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2006	$	15
2007		13
2008		12
2009		10
2010		1
Thereafter		2
Total	$	53

At December 31, 2005 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $6.9 million.

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G. Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, nuclear fuel contracts, construction projects and other commitments totaled $2.2 billion, $1.6 billion and $1.2 billion in 2005, 2004 and 2003, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2006	$	1,785
2007		839
2008		734
2009		646
2010		583
Thereafter		4,534
Total	$	9,121

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

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

11. SEGMENT OF BUSINESS INFORMATION

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

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

Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, is engaged in the purchase and sale, primarily at retail, of natural gas. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Transmission is comprised of SCPC, which is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G), and to industrial customers in South Carolina, and is regulated by the SCPSC.

Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the Georgia Public Service Commission. Energy Marketing markets electricity and natural gas to industrial, large commercial and wholesale customers, primarily in the Southeast.

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

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Disclosure of Reportable Segments (Millions of dollars)

2005	Electric Operations		Gas Distribution		Gas Transmission		Gas Retail Marketing		Energy Marketing			All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	1,909	$	1,168	$	237	$	664	$	799		$	70		$	(70	)	$	4,777
Intersegment Revenue		4		1		420		-		146			324			(895	)		-
Operating Income		299		75		21		n/a		n/a			n/a			41			436
Interest Expense		13		21		6		2		-			1			169			212
Depreciation and Amortization		450		49		7		3		-			14			(13	)		510
Income Tax Expense (Benefit)		4		18		7		14		(1	)		13			(173	)		(118	)
Net Income (Loss)		n/a		n/a		n/a		24		(1	)		(67	)		364			320
Segment Assets		5,531		1,701		390		284		128			590			895			9,519
Expenditures for Assets		280		122		4		-		1			19			(41	)		385
Deferred Tax Assets		n/a		n/a		6		8		3			2			7			26

2004	Electric Operations			Gas Distribution		Gas Transmission		Gas Retail Marketing		Energy Marketing			All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	1,688		$	914	$	212	$	552	$	520		$	58		$	(59	)	$	3,885
Intersegment Revenue		4			-		339		-		77			304			(724	)		-
Operating Income		550			67		19		n/a		n/a			n/a			(40	)		596
Interest Expense		10			21		5		3		-			-			163			202
Depreciation and Amortization		208			47		7		2		-			12			(11	)		265
Income Tax Expense (Benefit)		(2	)		15		5		18		(1	)		(8	)		96			123
Net Income (Loss)		n/a			n/a		n/a		29		(2	)		(39	)		269			257
Segment Assets		5,365			1,540		362		201		91			501			946			9,006
Expenditures for Assets		389			86		10		-		3			19			(6	)		501
Deferred Tax Assets		n/a			n/a		5		4		3			2			(4	)		10

2003	Electric Operations		Gas Distribution			Gas Transmission		Gas Retail Marketing		Energy Marketing			All Other		Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	1,466	$	870		$	217	$	448	$	416		$	56	$	(57	)	$	3,416
Intersegment Revenue		5		(1	)		303		-		-			277		(584	)		-
Operating Income		426		77			16		n/a		n/a			1		31			551
Interest Expense		7		21			5		4		-			1		162			200
Depreciation and Amortization		183		47			7		1		-			9		(9	)		238
Income Tax Expense (Benefit)		2		19			4		12		(1	)		9		90			135
Net Income (Loss)		n/a		n/a			n/a		20		(1	)		4		259			282
Segment Assets		5,038		1,477			334		133		53			702		721			8,458
Expenditures for Assets		655		68			18		-		-			38		(99	)		680
Deferred Tax Assets		n/a		n/a			5		6		2			44		(57	)		-

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

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

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

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

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

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

2005 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,266	$	891	$	1,127	$	1,493	$	4,777
Operating income		28		85		179		144		436
Net income		101		44		100		75		320
Basic and diluted earnings per share		.89		.39		.88		.65		2.81

2004 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,136	$	846	$	857	$	1,046	$	3,885
Operating income		194		123		161		118		596
Net income		101		60		54		42		257
Basic and diluted earnings per share		.91		.54		.48		.37		2.30

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			Page
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		95
		Overview	95
		Results of Operations	96
		Liquidity and Capital Resources	101
		Environmental Matters	104
		Regulatory Matters	107
		Critical Accounting Policies and Estimates	108
		Other Matters	110
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		110
Item 8.	Financial Statements and Supplementary Data
		Report of Independent Registered Public Accounting Firm	112
		Consolidated Balance Sheets	113
		Consolidated Statements of Income	115
		Consolidated Statements of Cash Flows	116
		Consolidated Statements of Changes in Common Equity	117
		Notes to Consolidated Financial Statements	118

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

OF OPERATIONS

Statements included in this discussion and analysis of South Carolina Electric & Gas Company (SCE&G, and together with its consolidated affiliates, the Company) (or elsewhere in this annual report) 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. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in the Company’s service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in the Company’s accounting policies, (9) weather conditions, especially in areas served by the Company, (10)  performance of SCANA Corporation’s (SCANA) pension plan assets and the impact on the Company’s results of operations, (11) inflation, (12) changes in environmental regulations and (13) the other risks and uncertainties described from time to time in the Company’s periodic reports filed with the SEC, including those risks described in Item 1A, Risk Factors. The Company disclaims any obligation to update any forward-looking statements.

OVERVIEW

SCE&G is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas. SCE&G’s 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 area extends into 26 counties covering more than 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 34 of the 46 counties in South Carolina and covers more than 22,000 square miles.

Key earnings drivers for SCE&G over the next five years will be additions to utility rate base, driven primarily by 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, controlling interest expense through continued debt reduction and limiting the growth of operation and maintenance expenses.

Electric Operations

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 and distribution of electricity in South Carolina. At December 31, 2005 SCE&G provided electricity to approximately 610,000 customers. GENCO owns and operates a coal-fired generation station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements. Both GENCO and Fuel Company are consolidated with SCE&G for financial reporting purposes.

Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. In January 2005, as a result of an electric rate case, SCE&G’s allowed return on equity was lowered from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. See further discussion at Liquidity and Capital Resources. Demand for electricity is primarily affected by weather, customer growth and the economy.

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

In February 2006 FERC issued final rules to implement the electric reliability provisions of the Energy Policy Act. The Company is reviewing these rules and will monitor their implementation to determine the impact they may have on SCE&G’s access to or cost of power for its native load customers and for its marketing of power outside its service territory. The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities. SCE&G:

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

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Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and is primarily engaged in the purchase and sale, primarily at retail, of natural gas in portions of South Carolina. At December 31, 2005 this segment provided natural gas to approximately 292,000 customers.

Operating results for gas distribution are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. This allowed return on equity was 12.25% for January 1 through October 31, 2005, when it was lowered to 10.25% as a result of a rate case.

Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact SCE&G’s ability to retain large commercial and industrial customers. Significant supply disruptions did occur in September and October 2005 as a result of hurricane activity in the Gulf of Mexico, resulting in the curtailment during the period of most large commercial and industrial customers with interruptible supply agreements. While supply disruptions are no longer being experienced, the price of natural gas remains volatile and has resulted in short-term competitive pressure. The long-term impact of volatile gas prices has not been determined.

RESULTS OF OPERATIONS

Net Income

Net income was as follows:

Millions of dollars	2005		% Change			2004		% Change			2003
Net income	$	258.1		11.0	%	$	232.5		4.6	%	$	222.2

• 2005 vs 2004 Net income increased primarily due to higher electric and gas margins of $50.8 million and $5.1 million, respectively, and due to the recognition of carrying cost recovery of $10.9 million on the dam remediation project (see further discussion at Recognition of Synthetic Fuel Tax Credits in Results of Operations). These increases were offset by higher major maintenance expenses of $4.1 million, higher depreciation and amortization expense of $16.1 million, increased interest expense of $3.3 million, increased expenses of $5.5 million associated with the Jasper County Electric Generation Station completed in May 2004, lower equity AFC of $14.3 million and higher other expenses of $2.3 million.

• 2004 vs 2003 Net income increased primarily due to higher electric margins of $62.2 million, partially offset by lower gas margins of $4.6 million, increased operations and maintenance expenses of $17.4 million, higher depreciation and amortization expense of $15.3 million, higher other taxes of $3.3 million and lower AFC of $3.5 million.

Pension Income

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

Millions of dollars	2005		2004		2003
Income Statement Impact:
(Component of) reduction in employee benefit costs	$	5.6	$	4.2	$	(1.0	)
Other income		12.2		11.0		8.2
Balance Sheet Impact:
(Component of) reduction in capital expenditures		1.6		1.2		(0.3	)
Component of (reduction in) amount due to Summer Station co-owner		0.6		0.4		(0.1	)
Total Pension Income	$	20.0	$	16.8	$	6.8

For the last several years, the market value of SCE&G’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income’s significant increase in 2004 is consistent with overall investment market results. See also the discussion of pension accounting in Critical Accounting Policies and Estimates.

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Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 1.5% of income before income taxes in 2005, 6.5% in 2004 and 8.4% in 2003.

The lower level of AFC for 2005 is primarily due to reductions in the levels of capital expenditures subsequent to the completion of the Jasper County Electric Generation Station in May 2004 and completion of the Lake Murray Dam project in May 2005.

Recognition of Synthetic Fuel Tax Credits

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. These synthetic fuel production facilities were placed in operation in 2000 and 2001. Under an accounting plan approved by the SCPSC in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were deferred until the SCPSC approved its application to offset capital costs of the Lake Murray Dam project as described below.

In a January 2005 order, the SCPSC approved SCE&G’s request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

The level of depreciation expense and related tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account is declining as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they have a significant impact on individual line items within the income statement. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment.The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2005 are as follows:

	Recognized			Year Ended
Factors Increasing (Decreasing) Net Income	4th Quarter			December 31,
Millions of dollars	2005			2005
Depreciation and amortization expense	$	(13.2	)	$	(214.0	)
Income tax benefits:
From synthetic fuel tax credits		10.9			179.0
From accelerated depreciation		5.0			81.8
From partnership losses		1.7			28.9
Total income tax benefits		17.6			289.7
Losses from Equity Method Investments		(4.4	)		(75.7	)
Impact on Net Income		-			-

Dividends Declared

SCE&G’s Board of Directors has declared the following dividends on common stock held by SCANA during 2005:

Declaration Date	Dividend Amount	Quarter Ended	Payment Date
February 17, 2005	$38.0 million	March 31, 2005	April 1, 2005
May 5, 2005	$38.0 million	June 30, 2005	July 1, 2005
July 27, 2005	$38.0 million	September 30, 2005	October 1, 2005
November 2, 2005	$38.0 million	December 31, 2005	January 1, 2006

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Electric Operations

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

Millions of dollars	2005		% Change			2004		% Change			2003
Operating revenues	$	1,912.0		13.0	%	$	1,692.0		15.0	%	$	1,471.7
Less: Fuel used in generation		618.1		32.4	%		466.9		39.7	%		334.1
Purchased power		37.2		(26.6	)%		50.7		(20.8	)%		64.0
Margin	$	1,256.7		7.0	%	$	1,174.4		9.4	%	$	1,073.6

• 2005 vs 2004 Margin increased by $41.4 million due to increased retail electric rates that went into effect in January 2005, by $24.8 million due to residential and commercial customer growth and by $16.4 million due to increased off-system sales. These increases were offset by a $2.4 million decrease due to unfavorable weather. Fuel used in generation increased $151.2 million due primarily to the increased cost of coal and natural gas used for electric generation. Purchased power decreased due to greater availability of generation facilities.

• 2004 vs 2003 Margin increased by $47.2 million due to increased off-system sales, by $22.9 million due to increased customer growth and consumption, by $22.3 million due to favorable weather and by $7.1 million due to the increase in retail electric base rates effective February 2003. Fuel used in generation increased by $103.0 million due to increased availability of generation facilities and by $30.0 million due to increased cost of coal. Purchased power decreased due to greater availability of generation facilities.

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

Classification (in thousands)	2005		% Change			2004		% Change			2003
Residential		7,634		2.3	%		7,460		6.6	%		6,998
Commercial		7,065		2.1	%		6,919		4.5	%		6,622
Industrial		6,651		(1.8	)%		6,775		3.5	%		6,548
Sales for resale (excluding interchange)		1,487		(2.5	)%		1,525		6.1	%		1,438
Other		527		0.2	%		526		5.2	%		500
Total territorial		23,364		0.7	%		23,205		5.0	%		22,106
NMST		1,794		(2.8	)%		1,845		*			425
Total		25,158		0.4	%		25,050		11.2	%		22,531

* Greater than 100%

• 2005 vs 2004 Territorial sales volumes increased by 407 MWh primarily due to customer growth partially offset by 261 MWh due to less favorable weather.

• 2004 vs 2003 Territorial sales volumes increased by 334 MWh and 774 MWh due to customer growth and weather, respectively.

Gas Distribution

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

Millions of dollars	2005		% Change			2004		% Change			2003
Operating revenues	$	508.8		28.0	%	$	397.4		10.4	%	$	360.1
Less: Gas purchased for resale		416.6		32.8	%		313.6		16.7	%		268.8
Margin	$	92.2		10.0	%	$	83.8		(8.2	)%	$	91.3

• 2005 vs 2004 Margin increased $4.7 million due to higher firm margin and $4.6 million due to increased retail gas base rates which became effective with the first billing cycle in November 2005. These increases were offset by a $0.8 million decrease due to lower interruptible margin and transportation revenue.

• 2004 vs 2003 Margin decreased primarily due to a decreased billing surcharge for the recovery of environmental remediation expenses of $5.0 million and lower residential and commercial sales volumes of $2.5 million.

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

Classification (in thousands)	2005	% Change	2004	% Change	2003
Residential	12,806	(0.9)%	12,916	(2.5)%	13,243
Commercial	12,553	3.3%	12,155	(1.4)%	12,322
Industrial	15,907	5.4%	15,087	3.9%	14,524
Transportation gas	2,032	(10.6)%	2,272	6.1%	2,141
Total	43,298	2.0%	42,430	0.5%	42,230

• 2005 vs 2004 Commercial and industrial volumes increased primarily due to more customers buying commodity gas instead of purchasing alternative fuels and instead of transporting gas purchased from others.

• 2004 vs 2003 Residential and commercial sales volumes decreased primarily due to unfavorable consumption patterns. Industrial and transportation volumes increased in 2004 primarily as a result of interruptible customers using gas instead of alternative fuels.

Other Operating Expenses

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

Millions of dollars	2005		% Change			2004		% Change			2003
Other operation and maintenance	$	441.2		2.4	%	$	431.0		7.0	%	$	402.9
Depreciation and amortization		464.8		*			220.9		12.6	%		196.2
Other taxes		131.0		(0.2	)%		131.3		4.2	%		126.0
Total	$	1,037.0		32.4	%	$	783.2		8.0	%	$	725.1

* Greater than 100%

• 2005 vs 2004 Other operation and maintenance expenses increased primarily due to increased electric generation major maintenance expenses of $6.7 million, increased expenses associated with the Jasper County Electric Generating Station completed in May 2004 of $2.4 million, increased nuclear operating and maintenance expenses of $2.4 million, higher expenses related to regulatory matters of $1.9 million and higher amortization of regulatory assets of $3.6 million. The increases were offset primarily by decreased long-term bonus and incentive plan expenses of $4.8 million and decreased storm damage expenses of $0.9 million. Depreciation and amortization increased approximately $214.0 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits), increased $6.5 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $6.1 million due to normal net property changes. In addition, pursuant to the January 2005 rate order, SCE&G began amortization of previously deferred purchased power costs and implemented new depreciation rates, resulting in $17.3 million of additional depreciation and amortization expense in the period.

• 2004 vs 2003 Other operation and maintenance expenses increased primarily due to increased labor and benefit expense of $19.5 million, $11.0 million of increased operating expenses at the electric generation plants and $2.5 million of expenses associated with winter storm restoration, partially offset by increased pension income of $5.2 million. Depreciation and amortization increased by $13.4 million due to completion of the Jasper County Electric Generating Station and $11.1 million due to normal additions. Other taxes increased primarily due to property taxes.

Interest Expense

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

Millions of dollars	2005		% Change			2004		% Change			2003
Interest on long-term debt, net	$	136.3		(5.9	)%	$	144.8		3.7	%	$	139.7
Other interest expense		11.0		*			3.5		(35.2	)%		5.4
Total	$	147.3		(0.7	)%	$	148.3		2.2	%	$	145.1

* Greater than 100%

• 2005 vs 2004 Interest on long-term debt decreased primarily due to the redemption of outstanding debt. Other interest expense increased primarily due to increased short-term debt.

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• 2004 vs 2003 Interest on long-term debt increased primarily due to slightly higher levels of borrowing outstanding during 2004 until the payment of maturing debt late in the year.

Income Taxes

Income taxes decreased approximately $269.9 million for the year 2005 compared to 2004 and increased approximately $10.2 million for the year 2004 compared to 2003. Changes in income taxes are primarily due to changes in operating income, although in 2005 tax benefits of synthetic fuel credits of $179.0 were also recognized pursuant to the January 2005 electric rate order. SCE&G’s effective tax rate has been favorably impacted in recent years by the flow-through of state investment tax credits and the equity portion of AFC.

LIQUIDITY AND CAPITAL RESOURCES

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

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of 2.89%, designed to produce additional annual revenues of $41.4 million based on a test year calculation. The SCPSC lowered SCE&G’s allowed return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G’s recovery of construction and operating costs for SCE&G’s new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. The SCPSC also approved recovery over a five-year period of SCE&G’s approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G’s Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year. No such additional depreciation was recognized in 2005, 2004 or 2003.

In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69%, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25% and became effective with the first billing cycle in November 2005.

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil and nuclear-fueled generation. On February 10, 2006, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station), announced their selection of the Summer Station site as the preferred site for a new nuclear plant should nuclear generation be considered the best alternative in the future. Due to the significant lead time required for construction of a nuclear plant, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). The COL application, which is expected to be completed and filed in 2007, would be reviewed by the NRC for an estimated three years. Issuance of a COL would not obligate the joint owners to build a nuclear plant. The final decision to build a nuclear plant will be influenced by several factors, including NRC licensing attainment, construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

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The Company’s current estimates of its cash requirements for construction and nuclear fuel expenditures for 2006-2008, which are subject to continuing review and adjustment, are as follows:

Estimated Cash Requirements

	2006		2007		2008
	Millions of dollars
SCE&G:
Electric Plant:
Generation (including GENCO)	$	128	$	86	$	193
Transmission		50		44		46
Distribution		115		114		115
Other		18		11		14
Nuclear Fuel		27		25		5
Gas		27		26		31
Common		22		17		7
Other		2		-		-
Total	$	389	$	323	$	411

The Company’s contractual cash obligations as of December 31, 2005 are summarized as follows:

Contractual Cash Obligations

(Millions of dollars)	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long-term and short-term debt
(including interest and preferred stock)	$	4,421	$	578	$	489	$	373	$	2,981
Capital leases		2		1		1		-		-
Operating leases		44		13		30		1		-
Purchase obligations		95		86		6		3		-
Other commercial commitments		672		327		285		14		46
Total	$	5,234	$	1,005	$	811	$	391	$	3,027

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

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

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

In addition to the contractual cash obligations above, SCANA sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded, and no further contributions are anticipated until after 2010. The Company’s cash payments under the health care and life insurance benefit plan were $8.2 million in 2005, and such annual payments are expected to increase to the $10-$11 million range in the future.

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

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Cash outlays for 2006 (estimated) and 2005 (actual) for certain expenditures are as follows:

	2006		2005
	Millions of dollars
Property additions and construction expenditures	$	368	$	331
Nuclear fuel expenditures		18		18
Investments		18		18
Total	$	404	$	367

Financing Limits and Related Matters

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

At December 31, 2005, SCE&G and Fuel Company had available the following lines of credit and short-term borrowings outstanding:

	Millions of dollars
Lines of credit (total and unused):
SCE&G and Fuel Company
Committed (expires June 2010)	$	525
Uncommitted		78(a	)
Short-term borrowings outstanding:
Commercial paper (270 or fewer days)	$	303.1
Weighted average interest rate		4.40	%

(a) Lines of credit that either SCE&G or SCANA may use.

SCE&G’s First and Refunding Mortgage Bond Indenture, dated January 1, 1945 (Old Mortgage) and covering substantially all of its properties, prohibits the issuance of additional bonds (Class A Bonds) unless net earnings (as therein defined) for 12 consecutive months out of the 18 months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2005, the Bond Ratio was 7.03. The Old Mortgage allows the issuance of Class A Bonds up to an additional principal amount equal to (i) 70% of unfunded net property additions (which unfunded net property additions certified to the trustee and other property eligible to be certified as property additions totaled approximately $2.0 billion at December 31, 2005), (ii) retirements of Class A Bonds (which retirement credits totaled $86.0 million at December 31, 2005), and (iii) cash on deposit with the Trustee.

SCE&G is also subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage. At December 31, 2005 approximately $1.2 billion Class A Bonds were on deposit with the Trustee of the New Mortgage and are available to support the issuance of additional New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 2005, the New Bond Ratio was 6.76.

SCE&G’s Restated Articles of Incorporation (the Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders unless net earnings (as therein defined) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2005, the Preferred Stock Ratio was 2.12.

The Articles also require the consent of a majority of the total voting power of SCE&G’s preferred stock before SCE&G may issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed ten percent of the aggregate principal amount of all of SCE&G’s secured indebtedness and capital and surplus (the ten percent test). No such consent is required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes. At December 31, 2005 the ten percent test would have limited issuances of unsecured indebtedness to approximately $419.5 million. Unsecured indebtedness at December 31, 2005 totaled approximately $246.6 million, and was comprised of short-term borrowings and the interest-free borrowing discussed below.

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In 2004 and 2005 SCE&G borrowed an aggregate $59 million available under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. Such borrowings are being repaid interest-free over ten years from the initial borrowing. At December 31, 2005 SCE&G had $50.2 million outstanding under the agreement.

Financing Cash Flows

During 2005 the Company experienced net cash outflows related to financing activities of approximately $64 million primarily due to the payment of dividends to SCANA.

In anticipation of the issuance of debt, the Company uses interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, SCE&G paid $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, SCE&G paid $3.5 million upon the termination of a forward starting interest rate swap.

In December 2005 SCE&G entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, an unrealized loss on this treasury lock agreement in the amount of $3.8 million has been recorded within other regulatory assets. If there is a loss on the ultimate settlement of this swap, such loss will be amortized over the life of the debt to which it relates.

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

ENVIRONMENTAL MATTERS

Capital Expenditures

For the three years ended December 31, 2005, the Company’s capital expenditures for environmental control totaled $199.2 million. These expenditures were in addition to expenditures included in “Other operation and maintenance” expenses, which were $25.2 million, $21.3 million, and $29.0 million during 2005, 2004 and 2003, respectively. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $66.8 million for 2006 and $314.1 million for the four-year period 2007 through 2010. These expenditures are included in the Company’s construction program discussed in Liquidity and Capital Resources, and include the matters discussed below.

Electric Operations

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company will be installing additional air quality controls to meet the CAIR requirements. Installation and operation and maintenance costs are currently being determined. Such costs are likely to be material and are expected to be recoverable through rates.

In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is negotiating with the South Carolina Department of Health and Environmental Control the terms of the state compliance proposals. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review and assessments. Such costs are likely to be material and are expected to be recoverable through rates.

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The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the DOJ has brought suit against a number of utilities in federal court alleging violations of the CAA. At least two of these suits have either been tried or have had substantive motions decided—one favorable to the industry and one not. The one not favorable to the Company is not binding as precedent and the one favorable to the Company likely is precedent and is consistent with current Company interpretation of the law and its resulting maintenance practices. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA, under a stringent rule known as New Source Review (NSR), that maintenance activities undertaken by the utilities over the past 20 or more years constitute “major modifications” which would have required the installation of costly Best Available Control Technology (BACT). SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of “major modifications,” including an exemption for routine repair, replacement or maintenance. On October 27, 2003 EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The new rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. The ultimate application of the final rule to the Company is uncertain. The Company has analyzed each of the activities covered by the EPA’s requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth.

The current state of continued DOJ enforcement actions is the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any enforcement actions relative to the Company’s, SCE&G’s or GENCO’s compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet CAIR regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $331 million over the 2006-2009 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $4 million in 2009 and $27 million in 2010 and subsequent years. To meet compliance requirements for the years 2011 through 2015, the Company anticipates additional capital expenditures totaling approximately $564 million.

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

Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 (the “Nuclear Waste Act”)required that the United States government, by January 31, 1998, accept and permanently dispose of high-level radioactive waste and spent nuclear fuel. The Nuclear Waste Act also imposes 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 (Standard Contract) with the DOE in 1983 providing for permanent disposal of its spent nuclear fuel in exchange for agreed payments fixed in the Standard Contract at particular amounts. On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of the Standard Contract, because as of the date of filing, the federal government had accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government’s breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. On January 9, 2006 SCE&G and Santee Cooper accepted a settlement from DOE which requires the payment by DOE of $9 million to the plaintiffs. The payment is to reimburse the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. SCE&G will record its portion ($6 million) of the settlement as a reduction to its fuel costs. As a result, most of the credit will be passed through to its customers through the fuel clause component of its retail electric rates. The settlement also provides for the plaintiffs to submit an annual application to DOE for the reimbursement of certain costs incurred subsequent to July 31, 2005. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through dry cask storage or other technology as it becomes available.

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Gas Distribution

The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate solely to regulated operations and are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.7 million and $10.5 million at December 31, 2005 and 2004, respectively. The deferral includes the estimated costs associated with the following matters:

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·   SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005, SCE&G has spent approximately $21.5 million to remediate the Calhoun Park site, and expects to spend an additional $0.3 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

·   SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by DHEC. The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of December 31, 2005, SCE&G has spent approximately $4.5 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped by it to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost arising from this matter is expected to be recoverable through rates.

REGULATORY MATTERS

See earlier discussion of increases in retail electric and gas base rates during 2005 in Liquidity and Capital Resources.

In February 2005, the Natural Gas Stabilization Act of 2005 (Stabilization Act) became law in South Carolina. The Stabilization Act 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.

Synthetic Fuel

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits.

The aggregate investment in these partnerships as of December 31, 2005 is approximately $3.9 million, and through December 31, 2005, they have generated and passed through to SCE&G approximately $188.3 million in tax credits. In a January 2005 order, the SCPSC approved SCE&G’s request to apply these tax credits, net of partnership losses and other expenses to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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

Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. The synthetic fuel tax credit program expires at the end of 2007.

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

While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. However, SCE&G’s analysis indicates that the synthetic fuel tax credits recorded in 2005 should not be impacted by the phase-out calculation. During 2006 and subject to continuing review of the estimated benchmark range and reference price of oil, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company’s ability to earn and utilize synthetic fuel tax credits in the future. However, the price volatility resulting from the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits in 2006 and 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

 If it is determined that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of December 31, 2005, remaining unrecovered costs, based on management’s recording of accelerated deprecation and related tax benefits on its assumption that 2005’s credits will not be subjected to the phase-out provisions, were $89.2 million.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Utility Regulation

The Company is subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected. See Note 1 to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2005, the Company’s net investments in fossil/hydro and nuclear generation assets were $2.3 billion and $552 million, respectively.

Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to each customer since the date of the last reading of their respective meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2005 and 2004, accounts receivable included unbilled revenues of $99.7 million and $80.6 million, respectively, compared to total revenues for 2005 and 2004 of $2.4 billion and $2.1 billion, respectively.

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Nuclear Decommissioning

Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Among the factors that could change the Company’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, as well as 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).

The Company’s share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357 million, stated in 1999 dollars. This estimate is based on a decommissioning study completed in 2000 which has not yet been updated to incorporate the 20-year license extension for Summer Station received in 2004. SCE&G expects to complete a new decommissioning study in 2006. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the NRC under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.

Under the Company’s method of funding decommissioning costs, funds collected through rates are invested in insurance policies on the lives of certain Company and affiliate personnel. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by SCE&G to an external trust fund. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

Accounting for Pensions and Other Postretirement Benefits

SCANA follows SFAS 87, “Employers’ Accounting for Pensions,” in accounting for its defined benefit pension plan. SCANA’s plan is fully funded and as such, net pension income is reflected in the financial statements (see Results of Operations). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension income of $20.0 million recorded in 2005 reflects the use of a 5.75% discount rate and an assumed 9.25% 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 5.5% in 2005 would have increased the Company’s share of SCANA’s pension income approximately $0.5 million. Had the assumed long-term rate of return on assets been 9.0%, the Company’s share of SCANA’s pension income for 2005 would have been reduced by approximately $2.0 million.

In determining the appropriate discount rate for 2005, SCANA considered the market indices of high-quality long-term fixed income securities and SCANA selected the discount rate of 5.75% as being within a reasonable range of interest rates for obligations rated Aa by Moody’s as of January 1, 2005. For 2006, the discount rate to be used will be 5.6%, which was derived using a cash flow matching technique which SCANA believes is preferable. The same discount rates were also selected for determination of other postemployment benefits costs discussed below.

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

SCANA determines the fair value of substantially all of its pension assets utilizing market quotes rather than utilizing any calculated values, “market related” values or other modeling techniques.

In developing the expected long-term rate of return assumptions, SCANA evaluates input from actuaries and from pension fund investment consultants. Such consultants’ 2005 review of the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 9.8%, 11.6%, 11.6% and 12.3%, respectively, all of which have been in excess of related broad indices. The 2005 expected long-term rate of return of 9.25% was based on a target asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2006, the expected rate of return will be 9.0%.

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

 Similar to its pension accounting, SCANA follows SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to 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 5.75% and recorded a net SFAS 106 cost of $12.3 million for 2005. Had the selected discount rate been 5.50%, the expense for 2005 would have been approximately $0.2 million higher.

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Asset Retirement Obligations

SFAS 143, together with FIN 47, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates to the Company’s regulated utility operations, adoption of SFAS 143 and FIN 47 had no impact on results of operations. As of December 31, 2005, the Company has recorded an ARO of approximately $132 million for nuclear plant decommissioning (as discussed above) and an ARO of approximately $178 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines, which was recorded under FIN 47. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made in many years in the future. Changes in these estimates will be recorded over time, but as stated above, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s regulated utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Financing

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

Claims and Litigation

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

	Expected Maturity Date
December 31, 2005 Millions of dollars	2006	2007	2008	2009	2010	Thereafter	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	169.9	39.2	39.2	139.2	39.2	1,714.4	2,141.1	2,051.3
Average Interest Rate (%)	8.51	6.86	6.86	6.33	6.86	5.88	6.17

	Expected Maturity Date
December 31, 2004 Millions of dollars	2005	2006	2007	2008	2009	Thereafter	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	189.2	169.9	39.2	39.2	139.2	1,718.2	2,294.9	2,285.7
Average Interest Rate (%)	7.37	8.51	6.86	6.86	6.33	6.02	6.36

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 table excludes approximately $97 million and $81 million in long-term debt as of December 31, 2005 and 2004, respectively, which amounts do not have a stated interest rate associated with them.

In December 2005 the Company entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005 the fair value of this treasury lock agreement was a loss of $3.8 million.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

South Carolina Electric & Gas Company:

We have audited the accompanying Consolidated Balance Sheets of South Carolina Electric & Gas Company and affiliates (the “Company”) as of December 31, 2005 and 2004, and the related Consolidated Statements of Income, Changes in Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of South Carolina Electric & Gas Company and affiliates at December 31, 2005 and 2004 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/Deloitte & Touche LLP

Columbia, South Carolina

March 1, 2006

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2005			2004
Assets
Utility Plant In Service:	$	7,687		$	7,096
Accumulated Depreciation and Amortization		(2,295	)		(1,934	)
		5,392			5,162
Construction Work in Progress		160			417
Nuclear Fuel, Net of Accumulated Amortization		28			42
Utility Plant, Net		5,580			5,621
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		28			27
Assets held in trust, net-nuclear decommissioning		52			49
Other investments		28			26
Nonutility Property and Investments, Net		108			102
Current Assets:
Cash and cash equivalents		19			20
Receivables, net of allowance for uncollectible accounts of $2 and $1		366			292
Receivables-affiliated companies		32			19
Inventories (at average cost):
Fuel		62			35
Materials and supplies		72			64
Emission allowances		54			9
Prepayments and other		12			30
Deferred income taxes		22			5
Total Current Assets		639			474
Deferred Debits:
Environmental		18			11
Pension asset, net		303			285
Due from affiliates-pension and postretirement benefits		31			23
Other regulatory assets		566			344
Other		121			125
Total Deferred Debits		1,039			788
Total	$	7,366		$	6,985

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December 31, (Millions of dollars)	2005		2004
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,362	$	2,164
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,468		2,270
Preferred Stock, net (Subject to purchase or sinking funds)		8		9
Long-Term Debt, net		1,856		1,981
Total Capitalization		4,332		4,260
Minority Interest		82		81
Current Liabilities:
Short-term borrowings		303		153
Current portion of long-term debt		183		198
Accounts payable		84		106
Accounts payable—affiliated companies		142		113
Customer deposits and customer prepayments		35		32
Taxes accrued		140		152
Interest accrued		35		35
Dividends declared		40		38
Other		38		28
Total Current Liabilities		1,000		855
Deferred Credits:
Deferred income taxes, net		801		765
Deferred investment tax credits		119		119
Asset retirement obligations		309		124
Non-legal asset retirement obligations		394		363
Due to affiliates-pension and postretirement benefits		12		14
Postretirement benefits		148		142
Other regulatory liabilities		94		198
Other		75		64
Total Deferred Credits		1,952		1,789
Commitments and Contingencies (Note 10)		-		-
Total	$	7,366	$	6,985

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, (Millions of dollars)	2005			2004			2003
Operating Revenues:
Electric	$	1,912		$	1,692		$	1,472
Gas		509			397			360
Total Operating Revenues		2,421			2,089			1,832
Operating Expenses:
Fuel used in electric generation		618			467			334
Purchased power		37			51			64
Gas purchased for resale		417			313			269
Other operation and maintenance		441			431			403
Depreciation and amortization		465			221			196
Other taxes		131			131			126
Total Operating Expenses		2,109			1,614			1,392
Operating Income		312			475			440
Other Income (Expense):
Other revenues		163			104			91
Other expenses		(140	)		(90	)		(74	)
Allowance for equity funds used during construction		-			14			18
Interest charges, net of allowance for borrowed funds used during construction of $3, $9 and $11		(144	)		(139	)		(136	)
Total Other Expense		(121	)		(111	)		(101	)
Income Before Income Taxes (Benefit), Losses from Equity Method Investments,
Minority Interest and Preferred Stock Dividends		191			364			339
Income Tax Expense (Benefit)		(150	)		120			110
Income Before Losses from Equity Method Investments, Minority
Interest and Preferred Stock Dividends		341			244			229
Losses from Equity Method Investments		(77	)		(2	)		(1	)
Minority Interest		6			10			8
Net Income		258			232			220
Preferred Stock Cash Dividends		7			7			7
Earnings Available for Common Shareholder	$	251		$	225		$	213

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2005			2004			2003
Cash Flows From Operating Activities:
Net income	$	258		$	232		$	220
Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities:
Losses from equity method investments		77			2			1
Minority interest		6			10			8
Depreciation and amortization		465			221			196
Amortization of nuclear fuel		18			22			21
Gain on sale of assets		(1	)		(1	)		(1	)
Allowance for equity funds used during construction		-			(14	)		(18	)
Carrying cost recovery		(11	)		-			-
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		(87	)		(19	)		(35	)
Inventories		(119	)		(44	)		-
Prepayments		18			(10	)		4
Pension asset		(17	)		(14	)		(5	)
Other regulatory assets		(30	)		(17	)		4
Deferred income taxes, net		19			44			51
Other regulatory liabilities		(165	)		42			46
Postretirement benefits		6			7			4
Accounts payable		6			(17	)		3
Taxes accrued		(12	)		34			4
Interest accrued		-			(4	)		8
Changes in fuel adjustment clauses		(32	)		8			11
Changes in other assets		(13	)		13			(5	)
Changes in other liabilities		24			36			42
Net Cash Provided From Operating Activities		410			531			559
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(330	)		(434	)		(589	)
Nonutility property additions		1			(5	)		-
Proceeds from sales of assets		2			2			2
Investments		(18	)		(20	)		(21	)
Net Cash Used For Investing Activities		(347	)		(457	)		(608	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		121			136			779
Contribution from parent		95			38			39
Repayment of debt		(264	)		(110	)		(441	)
Redemption of preferred stock		(1	)		-			(50	)
Dividends on equity securities		(158	)		(158	)		(159	)
Distribution to parent		-			(29	)		-
Short-term borrowings - affiliate, net		(7	)		-			(48	)
Short-term borrowings, net		150			13			(38	)
Net Cash Provided From (Used For) Financing Activities		(64	)		(110	)		82
Net Increase (Decrease) in Cash and Cash Equivalents		(1	)		(36	)		33
Cash and Cash Equivalents, January 1		20			56			23
Cash and Cash Equivalents, December 31	$	19		$	20		$	56
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $3, $9 and $11)	$	140		$	144		$	125
- Income taxes		26			22			41
Noncash Investing and Financing Activities:
Accrued construction expenditures		29			38			30

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY

			Premium	Other
			On	Paid		Capital		Total
	Common Stock (a)		Common	In		Stock	Retained	Common
	Shares	Amount	Stock	Capital		Expense	Earnings	Equity
	(Millions)
Balance at December 31, 2002	40	$181	$395	$627	$(5)		$768	$1,966
Capital Contributions From Parent				9				9
Earnings Available for Common Shareholder							213	213
Cash Dividends Declared							(145)	(145)
Balance at December 31, 2003	40	181	395	636	(5)		836	2,043
Capital Contributions From Parent				38				38
Earnings Available for Common Shareholder							225	225
Cash Dividends Declared							(142)	(142)
Balance at December 31, 2004	40	181	395	674	(5)		919	2,164
Capital Contributions From Parent				95				95
Earnings Available for Common Shareholder							251	251
Cash Dividends Declared							(148)	(148)
Balance at December 31, 2005	40	$181	$395	$769	$(5)		$1,022	$2,362

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

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.Organization and Principles of Consolidation

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

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

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

GENCO owns and operates a coal-fired electric generating station with a 615 megawatt net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase and related operating agreement. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $261 million) serves as collateral for its long-term borrowings.

B.Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 2005, approximately $584 million and $488 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	December 31,
	2005			2004
	Millions of dollars
Accumulated deferred income taxes, net	$	134		$	121
Under-(over-) collections-electric fuel and gas cost adjustment clauses, net		56			(2	)
Deferred purchased power costs		17			26
Deferred environmental remediation costs		18			11
Asset retirement obligations and related funding		240			76
Non-legal asset retirement obligations		(394	)		(363	)
Deferred synthetic fuel tax benefits, net		-			(97	)
Storm damage reserve		(38	)		(33	)
Franchise agreements		56			58
Deferred regional transmission organization costs		11			14
Other		(4	)		(17	)
Total	$	96		$	(206	)

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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-(over-) collections-electric fuel and gas cost adjustment clauses, net represent amounts under-(over-) collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings. See Note 1F.

Deferred purchased power costs-represents costs that were necessitated by outages at two of SCE&G’s base load generating plants in winter 2000-2001. The SCPSC approved recovery of these costs in base rates over a three year period beginning January 2005.

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates, of which $17.7 million remain.

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

Non-legal AROs represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

Deferred synthetic fuel tax benefits, net represented the deferral of partnership losses and other expenses offset by the tax benefits of those losses and expenses and accumulated synthetic fuel tax credits associated with SCE&G’s investment in two partnerships involved in converting coal to synthetic fuel. In 2005, under an accounting plan approved by the SCPSC, any tax credits generated from synthetic fuel produced by the partnerships and ultimately passed through to SCE&G, net of partnership losses and other expenses, have been used to offset the capital costs of constructing the back-up dam at Lake Murray. See Note 2.

The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. For the year ended December 31, 2005, no significant amounts were drawn from this reserve account. For the year ended December 31, 2004, $10.9 million was drawn from this reserve account.

Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are not earning a return, but are being amortized through cost of service over approximately 15 years.

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

The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

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C. System of Accounts

The Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The accounting records of the Company underlying the financial statements are maintained in accordance with the Uniform System of Accounts prescribed by FERC and as adopted by the SCPSC.

D.Utility Plant and Major Maintenance

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

The Company, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company’s portion of Summer Station was approximately $1.0 billion as of December 31, 2005 and 2004 (including amounts related to ARO). Accumulated depreciation associated with the Company’s share of Summer Station was $478.7 million and $463.7 million as of December 31, 2005 and 2004, respectively (including amounts related to ARO). The Company’s share of the direct expenses associated with operating Summer Station is included in “Other operation and maintenance” expenses and totaled $76.3 million, $74.5 million and $74.7 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, the Company is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2005, the Company incurred $4.9 million for turbine maintenance. The remaining $3.6 million is in a regulatory liability account on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and the Company begins accruing for each successive outage upon completion of the preceding outage. The Company accrued $0.8 million per month from January 2004 through June 2005 for its portion of the outage in April 2005 and is accruing approximately $1.0 million per month for its portion of the outage scheduled for October 2006. Total costs for the 2005 outage were approximately $22.3 million, of which the Company was responsible for approximately $14.9 million. Total costs for the planned outage in 2006 are estimated to be $25.7 million, of which the Company will be responsible for $17.2 million. As of December 31, 2005 and 2004, the Company had accrued $5.7 million and $9.9 million, respectively.

E. Allowance for Funds Used During Construction (AFC)

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 3.2%, 6.7% and 7.8% for 2005, 2004 and 2003, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred.

F.Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $99.7 million and $80.6 million as of December 31, 2005 and 2004, respectively.

107

Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. The Company had undercollected through the electric fuel cost component $44.1 million and $6.0 million at December 31, 2005 and 2004, respectively, which amounts are included in other regulatory assets.

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the SCPSC during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 2005 and 2004 the Company had undercollected (overcollected) $11.8 million and $(7.8) million, respectively, which amounts are also included in other regulatory assets or liabilities.

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

G.Depreciation and Amortization

Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 3.16%, 2.97% and 3.00% for 2005, 2004 and 2003, respectively. These rates reflect higher depreciation rates approved by the SCPSC in connection with electric and gas rate cases effective January 2005 and November 2005, respectively.

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

H.Nuclear Decommissioning

The Company’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.

Under the Company’s method of funding decommissioning costs, funds collected through rates ($3.2 million in each of 2005, 2004 and 2003) are invested in insurance policies on the lives of certain Company and affiliate personnel. Amounts for decommissioning collected through electric rates, insurance proceeds and interest on proceeds, less expenses, are transferred by the Company to an external trust fund. The trusteed asset balance reflects the net cash surrender value of the insurance policies held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

I.Income and Other Taxes

The Company is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including the Company, in the form of capital contributions. In 2005 capital contributions of $5.4 million were received by the Company under such provisions. In 2004, based upon a true-up of the parent’s tax benefit, the Company returned approximately $2.9 million in capital contributions received in 2003.

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

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

Long-term debt premium and discount are recorded in long-term debt and are being amortized as components of Interest Charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and amortized over the term of the replacement debt.

K. Environmental

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

L. Cash and Cash Equivalents

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

M.New Accounting Standards

SFAS 154, “Accounting Changes and Error Corrections,” was issued in June 2005. It requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

Effective December 15, 2005, the Company adopted Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations,” which was issued to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation 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.

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The following table presents conditional asset retirement obligations and related assets as recorded in the Consolidated Balance Sheet as of December 31, 2005, and the proforma amounts that would have been recorded as of December 31, 2004 and 2003 had FIN 47 been adopted at the beginning of 2003.

	December 31,			December 31,			December 31,
	2005			2004			2003
Millions of dollars	Actual			Proforma			Proforma
Assets:
Within utility plant	$	39		$	39		$	39
Within accumulated depreciation		(20	)		(20	)		(19	)
Within other regulatory assets		159			149			140
Total	$	178		$	168		$	160
Liabilities:
Asset retirement obligation	$	178		$	168		$	160

Due to the regulated nature of the business for which conditional asset retirement obligations were recognized, the adoption of FIN 47 did not have an impact on the Company’s results of operations, cash flows or financial position for the year ended December 31, 2005. Proforma net income and earnings per share for the periods prior to the adoption of FIN 47 would not differ from amounts actually recorded during these periods. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:

Millions of dollars	2005		2004
Beginning balance	$	124	$	117
Accretion expense		7		7
Adoption of FIN 47	$	178		-
Ending Balance	$	309	$	124

SFAS 123 (revised 2004),“Share-Based Payment,” was issued in December 2004 and will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB 25, “Accounting for Stock Issued to Employees.” The Company plans to adopt SFAS 123(R) in the first quarter of 2006 and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

N.Equity Compensation Plan

The Company participates in the SCANA Corporation Long-Term Equity Compensation Plan (the Plan), under which certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity-based compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, “Accounting for Stock Issued to Employees,” and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, “Accounting for Stock-Based Compensation,” and SFAS 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.”

 Options, all of which were granted prior to 2005, and all of which were fully vested as of December 31, 2005, were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates, therefore, no compensation expense has been recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma earnings available for common shareholder would have been as follows:

	2005		2004		2003
Earnings Available for Common Shareholder-as reported (millions)	$	250.8	$	225.2	$	213.1
Earnings Available for Common Shareholder-pro forma (millions)		250.6		224.1		211.4

The Company also grants other forms of equity-based compensation (performance awards) to certain employees. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $2.3 million, $8.4 million and $5.9 million for the years ended December 31, 2005, 2004 and 2003, respectively.

110

O.Affiliated Transactions

The Company has entered into agreements with certain affiliates to purchase all gas for resale to its distribution customers and to purchase electric energy. The Company purchases natural gas for resale and electric generation from South Carolina Pipeline Corporation (SCPC) and had approximately $72.1 million and $49.5 million payable to SCPC for such gas purchases at December 31, 2005 and 2004, respectively.

In 2005, the Company purchased approximately 338 miles of gas distribution pipeline from SCPC for approximately $21.7 million. In 2004, the Company purchased approximately 186 miles of gas distribution pipeline from SCPC for approximately $5.2 million. These amounts represented SCPC’s net book value in the underlying assets.

Total interest income, based on market interest rates, associated with the Company’s advances to affiliated companies in 2005 and 2004 was not significant. In 2003 such amounts were approximately $1.8 million.

The Company purchases natural gas and related pipeline capacity to supply its Jasper County Electric Generating Station from SCANA Energy Marketing, Inc. (SEMI). Such purchases totaled approximately $128.5 million and $79.7 million for the years ended December 31, 2005 and 2004, respectively. SCE&G had approximately $8.0 million and $4.5 million payable to SEMI for such purposes as of December 31, 2005 and 2004, respectively.

The Company holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. The Company had recorded as receivables from these affiliated companies of approximately $24.6 million and $18.6 million at December 31, 2005 and 2004, respectively. The Company had recorded as payables to these affiliated companies totaling approximately $25.3 million and $17.8 million at December 31, 2005 and 2004, respectively. The Company purchased approximately $248.1 million, $190.6 million and $145.2 million of synthetic fuel from these affiliated companies in 2005, 2004 and 2003, respectively.

Summarized combined financial information of unconsolidated affiliates as of and for the years ended December 31, 2005, 2004 and 2003, is presented below:

	2005			2004			2003
	Millions of dollars
Current assets	$	32		$	26		$	16
Non-current assets		7			10			12
Current liabilities		34			28			19
Non-current liabilities		-			-			-
Revenues		267			208			157
Gross loss		(8	)		(27	)		(24	)
Loss before income taxes		(55	)		(54	)		(45	)

P. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

Q. Use of Estimates

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

2.RATE AND OTHER REGULATORY MATTERS

Electric

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of 2.89%, designed to produce additional annual revenues of $41.4 million based on a test year calculation. The SCPSC lowered SCE&G’s allowed return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G’s recovery of construction and operating costs for SCE&G’s new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and, beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray Dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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In the January 2005 order, the SCPSC also approved recovery over a five-year period of SCE&G’s approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G’s Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year. No such additional depreciation was recognized in 2005, 2004 or 2003.

SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. SCE&G’s cost of fuel component in effect during 2005 and 2004 was as follows:

Rate Per KWh	Effective Date
$.01678	January-April 2004
$.01821	May-December 2004
$.01764	January-April 2005
$.02256	May-December 2005

Gas

In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69%, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25% and became effective with the first billing cycle in November 2005.

 SCE&G’s rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G’s cost of gas component in effect during 2005 and 2004 was as follows:

Rate Per Therm	Effective Date
$.877	January-October 2004
$.903	November 2004-October 2005

In October 2005, the SCPSC approved an increase in SCE&G’s cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general service classes, respectively. These new rates were effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006. Effective in December 2005, the SCPSC approved an increase in the cost of gas component to $1.36159, $1.28648 and $1.26253 per therm for residential, small and medium general service and large general service classes, respectively.

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Since January 1, 2006, the SCPSC has approved decreases in SCE&G’s cost of gas components from $1.36159, $1.28648 and $1.26253 to $1.22695, $1.15184 and $1.12789 per therm for residential, small and medium general service and large general service classes, respectively, effective February 14, 2006.

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

3.EMPLOYEE BENEFIT PLANS

The Company participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all permanent employees. The Company’s policy has been to fund the plan to the extent permitted by 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 who elected that option and for all new employees. For employees who elected to remain under the final average pay formula, benefits are based on years of credited service and the employee's average annual base earnings received during the last three years of employment. For employees under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits.

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

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

Changes in Benefit Obligations

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.

	Retirement Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
	Millions of dollars
Benefit obligation, January 1	$	669.5		$	619.9		$	197.5		$	188.4
Service cost		12.2			11.1			3.5			3.3
Interest cost		38.3			37.4			10.7			11.4
Plan participants’ contributions		-			-			2.3			1.1
Plan amendments		-			8.0			(0.3	)		4.7
Actuarial loss		27.1			24.1			1.5			1.2
Benefits paid		(35.6	)		(31.0	)		(13.1	)		(12.6	)
Benefit obligation, December 31	$	711.5		$	669.5		$	202.1		$	197.5

The accumulated benefit obligation for retirement benefits at the end of 2005 and 2004 was $664.4 million and $635.8 million, respectively. These accumulated retirement benefit obligations differ from the projected retirement benefit obligations above in that they reflect no assumptions about future compensation levels.

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

	2005			2004
Annual discount rate used to determine benefit obligations		5.60	%		5.75	%
Assumed annual rate of future salary increases for projected benefit obligation		4.00	%		4.00	%

A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5.0% for 2012 and to remain at that level thereafter. The effects of a one-percentage-point increase or decrease on accumulated other postretirement benefit obligation for health care benefits are as follows:

	1% Increase		1% Decrease
	Millions of dollars
Effect on postretirement benefit obligation	$	3.5	$	(3.1	)

In May 2004, the Financial Accounting Standards Board issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act” (“FSP 106-2”). FSP 106-2 provides definitive guidance on the recognition of the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 and related disclosure requirements for employers that sponsor prescription drug benefit plans for retirees. In the quarter beginning July 1, 2004 the Company adopted FSP 106-2. The expected subsidy reduced the accumulated postretirement benefit obligation (APBO) as of July 1, 2004 by $3.7 million, and net periodic cost for 2004 by $0.2 million, as compared to the amount calculated without considering the effects of the subsidy.

Changes in Plan Assets

	Retirement Benefits
	2005			2004
	Millions of dollars
Fair value of plan assets, January 1	$	846.7		$	787.7
Actual return on plan assets		43.2			90.0
Benefits paid		(35.6	)		(31.0	)
Fair value of plan assets, December 31	$	854.3		$	846.7

At the end of 2005 and 2004, the fair value of plan assets for the pension plan exceeded both the projected benefit obligation and the accumulated benefit obligation discussed above. Since the accumulated benefit obligation is less than the fair value of plan assets, there is no adjustment to other comprehensive income.

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Funded Status of Plans

	Retirement Benefits				Other Postretirement Benefits
	2005		2004		2005			2004
	Millions of dollars
Funded status, December 31	$	142.9	$	177.2	$	(202.1	)	$	(197.5	)
Unrecognized actuarial loss		88.4		28.2		44.4			44.2
Unrecognized prior service cost		71.3		78.3		5.2			6.4
Unrecognized net transition obligation		0.6		1.4		4.3			5.0
Net asset (liability) recognized in consolidated balance sheet	$	303.2	$	285.1	$	(148.2	)	$	(141.9	)

In connection with the joint ownership of Summer Station, as of December 31, 2005 and 2004, the Company recorded within deferred credits a $10.2 million and $9.7 million obligation, respectively, to Santee Cooper, representing an estimate of the net pension asset attributable to the Company’s contributions to the pension plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. As of December 31, 2005 and 2004, the Company also recorded within deferred debits a $7.1 million and $6.8 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.

Expected Cash Flows

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

			Other Postretirement Benefits*
Expected Benefit Payments	Pension Benefits		Excluding Medicare Subsidy		Including Medicare Subsidy
	Millions of dollars
2006	$	35.9	$	8.6	$	8.3
2007		37.7		9.2		8.9
2008		39.6		9.7		9.3
2009		41.6		10.0		9.6
2010		43.6		10.3		10.0
2011-2015		253.5		55.1		53.4

*Net of participant contributions

Net Periodic Cost

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

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Components of Net Periodic Benefit Cost (Income)

	Retirement Benefits									Other Postretirement Benefits
	2005			2004			2003			2005			2004			2003
	Millions of dollars
Service cost	$	12.2		$	11.1		$	9.5		$	3.5		$	3.3		$	2.7
Interest cost		38.3			37.4			36.7			10.7			11.4			11.4
Expected return on assets		(76.3	)		(71.0	)		(59.9	)		n/a			n/a			n/a
Prior service cost amortization		6.9			6.6			6.3			0.8			1.4			0.9
Actuarial loss		-			-			1.6			1.2			1.9			1.5
Transition amount amortization		0.8			0.8			0.8			0.8			0.8			0.8
Amount attributable to Company affiliates		(1.9	)		(1.7	)		(1.8	)		(4.8	)		(5.5	)		(5.3	)
Net periodic benefit (income) cost	$	(20.0	)	$	(16.8	)	$	(6.8	)	$	12.2		$	13.3		$	12.0

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

	Retirement Benefits									Other Postretirement Benefits
	2005			2004			2003			2005			2004			2003
Discount rate		5.75	%		6.00	%		6.50	%		5.75	%		6.00	%		6.50	%
Expected return on plan assets		9.25	%		9.25	%		9.25	%		n/a			n/a			n/a
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%
Health care cost trend rate		n/a			n/a			n/a			9.00	%		9.50	%		10.00	%
Ultimate health care cost trend rate		n/a			n/a			n/a			5.00	%		5.00	%		5.00	%
Year achieved		n/a			n/a			n/a			2011			2011			2011
Measurement date		Jan 1			Jan 1			Jan 1			Jan 1			Jan 1			Jan 1

The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $250,000.

Pension Plan Contributions

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

Pension Plan Asset Allocations

The Company’s pension plan asset allocation at December 31, 2005 and 2004 and the target allocations for 2006 are as follows:

	Target Allocation			Percentage of Plan Assets At December 31,
Asset Category	2006			2005			2004
Equity Securities		70	%		72	%		72	%
Debt Securities		30	%		28	%		28	%

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

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In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, which have all been in excess of related broad indices. The expected long-term rate of return of 9.25% assumes an asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2006 the expected rate of return will be 9.0%.

4.LONG-TERM DEBT

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

	Weighted-Average	Maturity	December 31,
	Interest Rate	Date	2005	2004
			Millions of dollars
First Mortgage Bonds (secured)	5.98%	2009-2035	$1,550	$1,700
First & Refunding Mortgage Bonds (secured)	9.00%	2006	131	131
GENCO Notes (secured)	5.97%	2011-2024	127	130
Industrial and Pollution Control Bonds	5.24%	2012-2032	156	156
Other		2006-2014	97	81
Total debt			2,061	2,198
Current maturities of long-term debt			(183)	(198)
Unamortized discount			(22)	(19)
Total long-term debt, net			$1,856	$1,981

  The annual amounts of long-term debt maturities and sinking fund requirements for the years 2006 through 2010 are summarized as follows:

Year	Amount
(Millions of dollars)
2006	$	183
2007		49
2008		48
2009		178
2010		45

Approximately $35.5 million of the long-term debt maturing in 2006 relates to a sinking fund requirement which may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee.

In 2004 and 2005 SCE&G borrowed an aggregate $59 million available under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. Such borrowings are being repaid interest-free over ten years from the initial borrowing. At December 31, 2005 SCE&G had $50.2 million outstanding under the agreement.

Substantially all utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.

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5.LINES OF CREDIT AND SHORT-TERM BORROWINGS

Details of lines of credit and short-term borrowings at December 31, 2005 and 2004, are as follows:

	2005			2004
	Millions of dollars
Lines of credit (total and unused)
Committed	$	525		$	525
Uncommitted		78(a	)		113(a	)
Short-term borrowings outstanding
Commercial paper (270 or fewer days)	$	303.1		$	152.9
Weighted average interest rate		4.40	%		2.40	%

(a) Lines of credit that either SCE&G or SCANA may use.

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

Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. All commercial paper borrowings are supported by five-year revolving credit facilities which expire on June 30, 2010.

Fuel Company commercial paper outstanding totaled $106.7 million and $31.3 million at December 31, 2005 and 2004, respectively, at weighted average interest rates of 4.39% and 2.44%, respectively.

SCE&G’s commercial paper outstanding totaled $196.4 million and $121.6 million at December 31, 2005 and 2004, respectively, at weighted average interest rates of 4.40% and 2.39%, respectively.

6. RETAINED EARNINGS

SCE&G’s Restated Articles of Incorporation contain provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2005, $51 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

7.PREFERRED STOCK

Retirements under sinking fund requirements are at par values. The aggregate of the annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 2006 through 2010 is $2.6 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2005 SCE&G had shares of preferred stock authorized and available for issuance as follows:

Par Value	Authorized	Available for Issuance
$100	1,000,000	-
$ 50	601,613	300,000
$ 25	2,000,000	2,000,000

Preferred Stock (Not subject to purchase or sinking funds)

For each of the three years ended December 31, 2005, SCE&G had outstanding 1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par Cumulative Preferred Stock (not subject to purchase or sinking funds).

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Preferred Stock (Subject to purchase or sinking funds)

Changes in “Total Preferred Stock (Subject to purchase or sinking funds)” during 2005, 2004 and 2003 are summarized as follows:

	Series
	4.50%, 4.60% (A) & 5.125%	4.60% (B) & 6.00%	Total Shares	Millions of Dollars
Redemption Price	$51.00	$50.50
Balance at December 31, 2002	83,849	116,124	199,973	$10.0
Shares Redeemed-$50 par value	(2,815)	(3,563)	(6,378)	(0.3)
Balance at December 31, 2003	81,034	112,561	193,595	9.7
Shares Redeemed-$50 par value	(2,516)	(6,600)	(9,116)	(0.5)
Balance at December 31, 2004	78,518	105,961	184,479	9.2
Shares Redeemed-$50 par value	(1,475)	(6,600)	(8,075)	(0.4)
Balance at December 31, 2005	77,043	99,361	176,404	$8.8

8.INCOME TAXES

Total income tax expense (benefit) attributable to income for 2005, 2004 and 2003 is as follows:

	2005			2004			2003
	Millions of dollars
Current taxes:
Federal	$	(8.4	)	$	47.4		$	23.7
State		9.5			(4.4	)		8.5
Total current taxes		1.1			43.0			32.2
Deferred taxes, net:
Federal		(7.5	)		28.1			41.7
State		(9.8	)		4.1			0.7
Total deferred taxes		(17.3	)		32.2			42.4
Investment tax credits:
Deferred-state		5.1			10.0			5.0
Amortization of amounts deferred-state		(1.9	)		(2.1	)		(1.8	)
Amortization of amounts deferred-federal		(2.7	)		(3.6	)		(3.6	)
Total investment tax credits		0.5			4.3			(0.4	)
Synthetic fuel tax credits - federal		(134.2	)		40.5			35.7
Total income tax expense (benefit)	$	(149.9	)	$	120.0		$	109.9

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

	2005			2004			2003
	Millions of dollars
Net income	$	258.1		$	232.5		$	220.5
Income tax expense (benefit)		(149.9	)		120.0			109.9
Minority interest		5.5			10.3			8.0
Total pre-tax income		113.7			362.8		$	338.4
Income taxes on above at statutory federal income tax rate	$	39.8		$	127.0		$	118.4
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		1.9			4.9			8.0
Synthetic fuel tax credits		(181.9	)		(2.9	)		(2.2	)
Allowance for equity funds used during construction		-			(5.0	)		(6.2	)
Non-taxable recovery of Lake Murray Dam project carrying costs		(3.8	)		-			-
Amortization of federal investment tax credits		(2.7	)		(3.6	)		(3.6	)
Amended returns for prior years		(2.1	)		-			-
Other differences, net		(1.1	)		(0.4	)		(4.5	)
Total income tax expense (benefit)	$	(149.9	)	$	120.0		$	109.9

The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $778.2 million at December 31, 2005 and $759.0 million at December 31, 2004 (see Note 1I) are as follows:

	2005		2004
	Millions of dollars
Deferred tax assets:
Nondeductible reserves	$	72.1	$	68.8
Unamortized investment tax credits		59.2		59.9
Federal alternative minimum tax credit carryforward		44.0		12.3
Deferred compensation		25.4		22.0
Unbilled revenue		16.4		7.0
Other		8.6		5.6
Total deferred tax assets		225.7		175.6
Deferred tax liabilities:
Property, plant and equipment		824.5		789.5
Pension plan benefit income		110.5		102.4
Deferred fuel costs		44.5		21.6
Other		24.4		21.1
Total deferred tax liabilities		1,003.9		934.6
Net deferred tax liability	$	778.2	$	759.0

Previously, the Internal Revenue Service had completed and closed examinations of the Company's consolidated federal income tax returns through tax years ending in 2000. In 2005, the Company filed amended federal income tax returns for 1998-2003, which are currently under examination. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on the earnings or the financial position of the Company. The IRS has also closed the examination of S. C. Coaltech No. 1 L.P., a synthetic fuel partnership in which the Company has an interest, for the 2000 tax year, resulting in that return being accepted as filed. The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed. As discussed in Note 1, certain synthetic fuel tax credits were deferred until 2005, at which time they began to be recognized for financial reporting purposes.

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9.FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal fair value at December 31, 2005 and 2004 were as follows:

	2005						2004
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	Millions of dollars
Long-term debt	$	2,038.3	$	2,125.8	$	2,179.4	$	2,347.6
Preferred stock (subject to purchase or sinking funds)		8.2		8.2		9.2		8.5

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

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

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

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

In anticipation of the issuance of debt, the Company also uses interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, the Company paid $3.5 million upon the termination of a forward starting interest rate swap. In December 2005 the Company entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005 an unrealized loss on this treasury lock agreement in the amount of $3.8 million has been recorded within deferred debits. If there is a loss on the ultimate settlement of this swap, such loss will be amortized over the life of the anticipated debt issuance to which it relates.

10. COMMITMENTS AND CONTINGENCIES

A. Nuclear Insurance

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

The Company currently maintains policies (for itself and on behalf of Santee Cooper, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, the Company’s portion of the retrospective premium assessment would not exceed $15.6 million.

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

B.Environmental

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. The Company has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

At the Company, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.7 million at December 31, 2005. The deferral includes the estimated costs associated with the following matters.

The Company owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. The Company anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005, the Company has spent approximately $21.5 million to remediate the Calhoun Park site, and expects to spend an additional $0.3 million. In addition, the National Park Service of the Department of the Interior made an initial demand to the Company for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by DHEC. The other sites are currently being investigated under work plans approved by DHEC. The Company anticipates that major remediation activities for the three sites will be completed in 2010. As of December 31, 2005, the Company has spent approximately $4.5 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped by it to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost arising from this matter is expected to be recoverable through rates.

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C. Franchise Agreements

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

D.Claims and Litigation

On August 21, 2003, the Company was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G, in South Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit. Since that time, the plaintiffs have dismissed defendants Duke Energy and Progress Energy and are proceeding against SCE&G only. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities’ internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may go to trial in 2006. The Company is confident of the propriety of its actions and intend to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

On May 17, 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated, v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit Court (the Court). The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than the Company’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Court granted the Company’s motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has appealed. The Company intends to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality’s limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations are also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, the Company filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to the Company’s electric and gas service, to approve the Company’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.

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E.Other Contingency

In 2004 and early 2005, SCANA and certain of its affiliates, like other integrated utilities, were the subject of an investigation by FERC’s Office of Market Oversight and Investigations (OMOI) focusing, among other things, on the relationship between SCE&G’s merchant and transmission functions. These relationships are among those addressed in FERC Order 2004, a primary purpose of which order is to ensure that affiliates of transmission providers have no marketplace advantage over non-affiliated market participants. In connection with that investigation, SCE&G was assessed no monetary damages or penalties; however, under terms of a Settlement and Consent Agreement entered into on April 1, 2005, and approved by FERC order dated April 27, 2005, SCE&G agreed to the implementation of a compliance plan which includes periodic reports to OMOI.

On January 2, 2006, SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgment of SCE&G’s discovery that it may have improperly utilized network transmission services, rather than point-to-point transmission services, for purchases and sales of electricity in violation of SCE&G’s open access transmission tariff and applicable orders under the Federal Power Act that prohibit the use of network transmission service in support of certain “off-system” sales. This acknowledgement was in part the result of SCE&G’s preliminary review of a FERC order issued following its examination of another energy provider in September 2005. Upon further review of that order and a comprehensive analysis, SCE&G has now determined and notified FERC that it did improperly utilize network transmission service in a large number of purchase and sale transactions.

In response to this discovery, SCE&G has notified FERC and has ceased participation in such transactions, has instituted additional self-restrictive procedures as safeguards to ensure full compliance in this area in the future, has committed to certain modifications to its compliance plan, including increased levels of training and monitoring, and is fully cooperating with OMOI to resolve this matter.

As of December 31, 2005, SCE&G has recorded a loss accrual in the amount of approximately $0.8 million based on its estimation of net revenues from these transactions that occurred after the date of the Settlement and Consent Agreement and that might be subject to disgorgement pursuant to FERC orders. However, there remains uncertainty as to what additional actions may be taken by FERC. Potential actions could include further modifications to the compliance plan or other non-monetary remedies. In addition to the disgorgement of profits, such remedies could also include penalties of up to a maximum of $1 million per violation or per day since August 8, 2005, the effective date of the Energy Policy Act of 2005. SCE&G estimates that there were approximately 1,200 of these transactions since August 8, 2005, that, despite the immaterial profits from the transactions, could be deemed in violation of FERC's rule on the use of network transmission service. In light of SCE&G’s self-reporting and other cooperation in the investigation of this matter, SCE&G’s belief that no market participants or customers of SCE&G were harmed or disadvantaged by the transactions, and SCE&G’s institution of appropriate safeguards referred to above, SCE&G does not believe that such sanctions are warranted. Nonetheless, SCE&G cannot predict what, if any, actions FERC will take with respect to this matter, and is unable to determine if the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.

F.Operating Lease Commitments

The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2010. Rent expense totaled approximately $11.7 million, $9.9 million and $9.9 million in 2005, 2004 and 2003, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2006	$	13
2007		11
2008		10
2009		9
2010		1
	$	44

At December 31, 2005, minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $6.9 million.

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G.Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended for coal supply, nuclear fuel contracts, construction projects and other commitments totaled $439.4 million, $348.3 million and $276.5 million in 2005, 2004 and 2003, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2006	$	414
2007		164
2008		92
2009		35
2010		7
Thereafter		55
	$	767

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

11.SEGMENT OF BUSINESS INFORMATION

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

Electric Operations is primarily engaged in the generation, transmission, and distribution of electricity, and is regulated by the SCPSC and FERC. Gas Distribution is engaged in the purchase and sale, primarily at retail, of natural gas, and is regulated by the SCPSC.

Disclosure of Reportable Segments (Millions of dollars)

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

2004	Electric Operations	Gas Distribution	All Other	Adjustments/ Eliminations	Consolidated Total
Customer Revenue	$1,692	$397	-	-	$2,089
Intersegment Revenue	-	1	-	$(1)	-
Operating Income (Loss)	550	14	-	(89)	475
Interest Expense	10	-	-	129	139
Depreciation and Amortization	208	13	-	-	221
Segment Assets	5,365	354	$3	1,263	6,985
Expenditures for Assets	389	35	-	15	439
Deferred Tax Assets	n/a	n/a	-	5	5

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2003	Electric Operations	Gas Distribution	All Other	Adjustments/ Eliminations	Consolidated Total
Customer Revenue	$1,472	$360	-	-	$1,832
Intersegment Revenue	-	1	-	$(1)	-
Operating Income (Loss)	426	15	-	(1)	440
Interest Expense	7	-	$2	127	136
Depreciation and Amortization	183	13	-	-	196
Segment Assets	5,038	323	3	1,264	6,628
Expenditures for Assets	655	20	-	(86)	589
Deferred Tax Assets	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, the Company does not allocate interest charges, income tax expense (benefit) or assets other than utility plant to its segments. Interest income is not reported by segment and is not material. In accordance with SFAS 109, the Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

The Consolidated Financial Statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total revenue remove revenues from non-reportable segments. Segment assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense, Expenditures for Assets and Deferred Tax Assets include the totals from the Company that are not allocated to the segments.

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

2005 Millions of dollars	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	573		$	523	$	696	$	629	$	2,421
Operating income (loss)		(59	)		78		178		115		312
Net income		52			40		106		62		260

2004 Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	527	$	503	$	555	$	504	$	2,089
Operating income		113		114		162		86		475
Net income		54		57		85		36		232

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OF NORTH CAROLINA, INCORPORATED

			Page
Item 7.	Management’s Narrative Analysis of Results of Operations		141
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		144
Item 8.	Financial Statements and Supplementary Data
		Report of Independent Registered Public Accounting Firm	146
		Consolidated Balance Sheets	147
		Consolidated Statements of Income	149
		Consolidated Statements of Cash Flows	150
		Consolidated Statements of Changes in Common Equity	151
		Notes to Consolidated Financial Statements	152

Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore is filing this form with the reduced disclosure format allowed under General Instruction I(2).

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ITEM 7. MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

Statements included in this narrative analysis of Public Service Company of North Carolina, Incorporated’s (together with its consolidated subsidiaries, PSNC Energy) (or elsewhere in this annual report) 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. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in PSNC Energy’s service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in PSNC Energy’s accounting policies, (9) weather conditions, especially in areas served by PSNC Energy, (10) performance of SCANA Corporation’s (SCANA) pension plan assets and the impact on PSNC Energy’s results of operations, (11) inflation, (12) changes in environmental regulations, and (13) the other risks and uncertainties described from time to time in PSNC Energy’s periodic reports filed with the SEC including those described in Item 1A, Risk Factors. PSNC Energy disclaims any obligation to update any forward-looking statements.

Net Income

Net income for the years ended December 31, 2005 and 2004 was as follows:

	2005		% Change			2004
	Millions of dollars
Net income	$	25.7		8.4	%	$	23.7

Net income increased $2.0 million, primarily due to increased margins on sales of natural gas.

The nature of PSNC Energy’s business is seasonal. The quarters ending March 31 and December 31 are generally PSNC Energy’s most profitable quarters due to increased demand for natural gas related to space heating requirements.

PSNC Energy’s Board of Directors authorized the following distributions/dividends on common stock held by SCANA during 2005:

Declaration Date	Distribution	Quarter Ended	Payment Date
February 17, 2005	$3.5 million	March 31, 2005	April 1, 2005
May 5, 2005	$3.5 million	June 30, 2005	July 1, 2005
July 27, 2005	$4.0 million	September 30, 2005	October 1, 2005
November 2, 2005	$4.0 million	December 31, 2005	January 1, 2006

Gas Distribution

Gas distribution sales margins for 2005 and 2004 were as follows:

	2005		2004		Change		% Change
	Millions of dollars
Operating revenues	$	659.8	$	516.5	$	143.3		27.7	%
Less: Cost of gas		478.0		341.6		136.4		39.9	%
Gross margin	$	181.8	$	174.9	$	6.9		3.9	%

Gas distribution sales margin increased primarily due to customer growth.

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Income Taxes

Income taxes changed primarily as a result of changes in operating and other income.

Capital Expansion Program and Liquidity Matters

PSNC Energy’s capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy’s 2006 construction budget is approximately $71.0 million, compared to actual construction expenditures for 2005 of $64.4 million.

The U. S. Congress passed the Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directing the U. S. Department of Transportation to establish a pipeline integrity management rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy’s approximately 720 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 110 miles are located within these areas. Fifty percent of these miles of pipeline must be assessed by December 2007, and the remainder by December 2012. Depending on the assessment method used, PSNC Energy will be required to reinspect these same miles of pipeline every five to seven years. Though cost estimates for this project were developed using various assumptions, each of which are subject to imprecision, PSNC Energy currently estimates the total cost to be $8 million for the initial assessments and any subsequent remediation required through December 2012.

In the second quarter of 2006, PSNC Energy plans to file with the NCUC a request to increase base rates. Specific details related to the timing and size of the filing have not been finalized.

PSNC Energy’s contractual cash obligations as of December 31, 2005 are summarized as follows:

Contractual Cash Obligations

(Millions of dollars)	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long-term and short-term debt (including interest)	$	577	$	121	$	65	$	182	$	209
Operating leases		1		1		-		-		-
Purchase obligations		60		55		5		-		-
Other commercial commitments		859		408		168		110		173
Total	$	1,497	$	585	$	238	$	292	$	382

Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases, transportation and storage. Many of these forward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts. Because these contracts relate to regulated gas businesses, their effects on gas costs are reflected in gas rates.

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

PSNC Energy also has other conditional asset retirement obligations that are not listed in the contractual cash obligations table. See Note 1L to the consolidated financial statements.

In addition to the contractual cash obligations above, SCANA sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded, and no further contributions are anticipated until after 2010. PSNC Energy’s cash payments under the health care and life insurance benefit plan were approximately $1.6 million in 2005, and such annual payments are expected to increase to the $2-$3 million range in the future.

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Financing Limits and Related Matters

PSNC Energy’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including the NCUC. The Indenture under which these securities are issued contains no specific limit on the amount which may be issued.

At December 31, 2005 PSNC Energy had available the following lines of credits and short-term borrowings outstanding:

	Millions of dollars
Committed lines of credit (expires June 2010)	$	125
Short-term borrowings outstanding:
Commercial paper (270 or fewer days)	$	99
Weighted average interest rate		4.47	%

PSNC Energy is party to one interest rate swap agreement which allows it to pay variable rates and receive fixed rates on a notional amount of $22.4 million at December 31, 2005. See Note 7 to the consolidated financial statements. PSNC Energy does not engage in off-balance sheet financings or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture and equipment.

Competition

Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact PSNC Energy’s ability to retain large commercial and industrial customers on a monthly basis.

The NCUC has approved a rate structure that allows PSNC Energy to negotiate reduced rates in order to match the cost of alternate fuels to large commercial and industrial customers and recover the lost margin from other classes of customers. PSNC Energy anticipates that the need to negotiate reduced rates with these customers will continue.

Critical Accounting Policies and Estimates

Following are descriptions of PSNC Energy’s accounting policies which are most critical in terms of reporting financial condition or results of operations.

SFAS 71—PSNC Energy is subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, PSNC Energy may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations of PSNC Energy’s Gas Distribution segment in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected. See Note 1 to the consolidated financial statements for a description of PSNC Energy’s regulatory assets and liabilities, including those associated with PSNC Energy’s environmental assessment program.

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Certain of PSNC Energy’s regulatory assets and other deferred liabilities arise from its environmental assessment program, which identifies and evaluates current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Regulatory assets and other deferred liabilities related to environmental cleanup affect primarily the Gas Distribution segment and are due to the costs associated with current and former MGP sites.

Revenue Recognition / Unbilled Revenues—Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their gas meters, PSNC Energy records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of gas delivered to each customer since the date of the last reading of their respective meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2005 and 2004, accounts receivable included unbilled revenues of $69.6 million and $50.0 million, respectively, compared to total revenues for 2005 and 2004 of $659.8 million and $516.5 million, respectively.

Asset Retirement Obligations

SFAS 143, together with FIN 47, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates primarily to PSNC Energy’s regulated utility operations, adoption of SFAS 143 and FIN 47 had no significant impact on results of operations. As of December 31, 2005, PSNC Energy has recorded an ARO of approximately $13 million for other conditional obligations related to gas pipeline properties which was recorded under FIN 47. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. Changes in these estimates will be recorded over time, but as stated above, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for PSNC Energy remains in place.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

All financial instruments held by PSNC Energy described below are held for purposes other than trading.

Interest rate risk—The tables below provide information about long-term debt issued by PSNC Energy 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 and related maturities. Fair values for debt and swaps represent quoted market prices.

	Expected Maturity Date
December 31, 2005 Millions of dollars	2006	2007	2008	2009	2010	Thereafter	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	3.2	3.2	3.2	3.2	3.2	256.4	272.4	309.4
Average Fixed Interest Rate (%)	8.75	8.75	8.75	8.75	8.75	6.9	7.0
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	3.2	3.2	3.2	6.4	22.4	0.4
Average Pay Interest Rate (%)	7.7	7.7	7.7	7.7	7.7	7.7	7.7
Average Receive Interest Rate (%)	8.75	8.75	8.75	8.75	8.75	8.75	8.75

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	Expected Maturity Date
December 31, 2004 Millions of dollars	2005	2006	2007	2008	2009	Thereafter	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	3.2	3.2	3.2	3.2	3.2	259.6	275.6	325.8
Average Fixed Interest Rate (%)	8.75	8.75	8.75	8.75	8.75	6.9	7.0
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	3.2	3.2	3.2	9.6	25.6	1.2
Average Pay Interest Rate (%)	5.74	5.74	5.74	5.74	5.74	5.74	5.74
Average Receive Interest Rate (%)	8.75	8.75	8.75	8.75	8.75	8.75	8.75

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.

PSNC Energy hedges gas purchasing activities using NYMEX futures, options and swaps. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as regulatory assets and liabilities for the over or under recovery of gas costs. In a September 2005 order, in connection with PSNC Energy’s 2005 annual prudency review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonably and prudently incurred during the 12-month review period ended March 31, 2005.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Public Service Company of North Carolina, Incorporated:

We have audited the accompanying Consolidated Balance Sheets of Public Service Company of North Carolina, Incorporated and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related Consolidated Statements of Income, Changes in Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit 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 Public Service Company of North Carolina, Incorporated and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Columbia, South Carolina

March 1, 2006

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CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)	2005			2004
Assets
Gas Utility Plant	$	1,006		$	947
Accumulated Depreciation		(282	)		(262	)
Acquisition Adjustment		210			210
Gas Utility Plant, Net		934			895
Nonutility Property and Investments, Net		28			27
Current Assets:
Cash and cash equivalents		3			2
Restricted cash and temporary investments		1			8
Receivables, net of allowance for uncollectible accounts of $3 and $2		182			128
Receivables—affiliated companies		9			7
Inventories (at average cost):
Stored gas		92			70
Materials and supplies		6			5
Deferred income taxes, net		-			1
Other		3			3
Total Current Assets		296			224
Deferred Debits:
Due from affiliate-pension asset		11			12
Regulatory assets		26			26
Other		3			4
Total Deferred Debits		40			42
Total	$	1,298		$	1,188

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December 31, (Millions of dollars)	2005		2004
Capitalization and Liabilities
Capitalization:
Common equity	$	528	$	513
Long-term debt, net		270		274
Total Capitalization		798		787
Current Liabilities:
Short-term borrowings		99		58
Current portion of long-term debt		3		3
Accounts payable		91		66
Accounts payable-affiliated companies		6		8
Customer deposits and customer prepayments		14		14
Taxes accrued		4		4
Interest accrued		6		6
Distributions/dividends declared		4		4
Deferred income taxes, net		3		-
Other		6		11
Total Current Liabilities		236		174
Deferred Credits:
Deferred income taxes, net		104		102
Deferred investment tax credits		1		1
Due to affiliate-postretirement benefits		19		19
Other regulatory liabilities		23		11
Asset retirement obligations		13		-
Non-legal asset retirement obligations		91		84
Other		13		10
Total Deferred Credits		264		227
Commitments and Contingencies (Note 8)		-		-
Total	$	1,298	$	1,188

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, (Millions of dollars)	2005			2004			2003
Operating Revenues	$	660		$	516		$	509
Cost of Gas		478			341			330
Gross Margin		182			175			179
Operating Expenses:
Operation and maintenance		80			80			75
Depreciation and amortization		35			34			34
Other taxes		8			8			7
Total Operating Expenses		123			122			116
Operating Income		59			53			63
Other Income (Expense):
Other revenues		12			11			13
Other expenses		(9	)		(8	)		(10	)
Loss on sale of assets		-			(1	)		-
Allowance for equity funds used during construction		-			-			1
Interest charges, net of allowance for borrowed funds used during construction		(21	)		(21	)		(21	)
Total Other Expense		(18	)		(19	)		(17	)
Income Before Income Taxes and Earnings from Equity Method Investments		41			34			46
Income Tax Expense		19			14			19
Income Before Earnings from Equity Method Investments		22			20			27
Earnings from Equity Method Investments		4			4			4
Net Income	$	26		$	24		$	31

See Notes to Consolidated Financial Statements.

136

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)	2005			2004			2003
Cash Flows From Operating Activities:
Net income	$	26		$	24		$	31
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization		37			37			36
Loss on sale of assets		-			1			-
Allowance for funds used during construction		-			-			(1	)
Cash provided (used) by changes in certain assets and liabilities
Receivables, net		(56	)		(15	)		(18	)
Inventories		(25	)		(15	)		(18	)
Regulatory assets		(5	)		2			-
Regulatory liabilities		1			1			-
Accounts payable		13			15			(9	)
Deferred income taxes, net		6			8			5
Taxes accrued		-			(6	)		5
Changes in gas adjustment clauses		26			(11	)		11
Changes in other assets		1			-			-
Changes in other liabilities		(3	)		2			4
Net Cash Provided From Operating Activities		21			43			46
Cash Flows From Investing Activities:
Construction expenditures, net of AFC		(52	)		(40	)		(38	)
Proceeds on sale of assets		-			-			12
Nonutility and other		5			(1	)		(1	)
Net Cash Used For Investing Activities		(47	)		(41	)		(27	)
Cash Flows From Financing Activities:
Short-term borrowings, net		41			3			24
Contributions from parent		3			1			1
Repayment of debt		(3	)		(8	)		(8	)
Distributions/dividends		(14	)		(14	)		(19	)
Net Cash Provided From (Used For) Financing Activities		27			(18	)		(2	)
Net Increase (Decrease) in Cash and Cash Equivalents		1			(16	)		17
Cash and Cash Equivalents, January 1		2			18			1
Cash and Cash Equivalents, December 31	$	3		$	2		$	18
Supplemental Cash Flow Information:
Cash paid for: Interest (net of capitalized interest of $1, $1 and $1)	$	19		$	19		$	19
Income taxes		11			11			8
Noncash Investing and Financing Activities:
Accrued construction expenditures		3			3			2

See Notes to Consolidated Financial Statements.

137

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY

				Accumulated
			Capital	Other	Retained	Total
	Common Stock		in Excess	Comprehensive	Earnings	Common
	Shares	Amount	of Par	Loss	(Deficit)	Equity
	(Millions)
Balance at December 31, 2002	1,000	-	$686	$(1)	$(198)	$487
Capital Contributions From Parent, net			1			1
Net Income					31	31
Cash Distributions/Dividends Declared			(17)			(17)
Balance at December 31, 2003	1,000	-	$670	$(1)	$(167)	$502
Capital Contributions From Parent, net			1			1
Net Income					24	24
Cash Distributions/Dividends Declared			(14)			(14)
Balance at December 31, 2004	1,000	-	$657	$(1)	$(143)	$513
Capital Contributions From Parent, net			3			3
Net Income					26	26
Cash Distributions/Dividends Declared			(14)			(14)
Balance at December 31, 2005	1,000	-	$646	$(1)	$(117)	$528

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.Organization and Principles of Consolidation

Public Service Company of North Carolina, Incorporated (PSNC Energy, and together with its consolidated subsidiaries, the Company), a public utility, was organized as a North Carolina corporation in 1938. Effective January 1, 2000, SCANA Corporation (SCANA), a South Carolina holding company, acquired the Company. As a result, the Company became a wholly owned subsidiary of SCANA, incorporated under the laws of South Carolina. The Company is engaged predominantly in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina.

The accompanying Consolidated Financial Statements include the accounts of PSNC Energy and its subsidiary companies, Clean Energy Enterprises, Inc., PSNC Blue Ridge Corporation, and PSNC Cardinal Pipeline Company. Investments in other affiliates in which the Company has the ability to exercise influence over operating and financial policies are accounted for under the equity method. Significant intercompany balances and transactions have been eliminated in consolidation.

B.Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded, as of December 31, 2005, approximately $26 million and $114 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	December 31,
	2005			2004
	Millions of dollars
Excess deferred income taxes	$	(2	)	$	(1	)
Under- (over-) collections-gas cost adjustment clause, net		(15	)		11
Deferred environmental remediation costs		10			8
Asset retirement obligations		10			-
Non-legal asset retirement obligations		(91	)		(84	)
Total	$	(88	)	$	(66	)

Excess deferred income taxes represent deferred income taxes recorded in prior years at a rate higher than the current statutory rate. Pursuant to a North Carolina Utilities Commission (NCUC) order, the Company is required to refund these amounts to customers through a rate decrement.

Under-(over-) collections—gas cost adjustment clause, net represents amounts under- or over-collected from customers pursuant to the Company’s Rider D mechanism approved by the NCUC. This mechanism allows the Company to recover all prudently incurred gas costs, including costs incurred from hedging activities. See Note 1F.

Deferred environmental remediation costs represents costs associated with the assessment and cleanup of manufactured gas plant (MGP) sites currently or formerly owned by the Company. A portion of the costs incurred has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered through rates are $3.1 million. See Note 8A. Management believes these costs and the estimated remaining costs of $7.4 million will be recoverable.

Asset Retirement Obligations (ARO) represents the regulatory asset associated with conditional AROs recorded by SFAS 143, “Accounting for Asset Retirement Obligations,” and Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations.”

Non-legal AROs represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

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The NCUC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the NCUC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by the Company. However, ultimate recovery is subject to NCUC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C. System of Accounts

The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the NCUC.

D. Utility Plant

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

E. Allowance for Funds Used During Construction (AFC)

AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 10%, 8% and 12.7% for the years ended December 31, 2005, 2004 and 2003, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561.

F.Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers, and include estimated amounts for natural gas delivered and facilities charges not yet billed. Unbilled revenues totaled $69.6 million and $50.0 million as of December 31, 2005 and 2004, respectively.

The Company’s Rider D mechanism authorizes the recovery of all prudently incurred gas costs from customers. Any difference in amounts paid and collected for these costs is deferred for subsequent refund to or collection from customers, with interest. Realized and unrealized gains and losses from the Company’s hedging activities are also included in the Rider D mechanism. Additionally, the Company can recover its margin losses on negotiated gas sales to certain large commercial/industrial customers in a manner authorized by the NCUC. Effective December 1, 2005, the Company may also recover certain uncollectible expenses related to gas cost. Pursuant to the operation of Rider D, at December 31, 2005 the Company had overcollected from customers approximately $15 million, net. The Company had undercollected from customers approximately $11 million, net, at December 31, 2004.

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The Company’s gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions. The Company establishes its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas as approved by the NCUC.

G.Depreciation and Amortization

Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 3.8%, 3.9% and 4.1% for 2005, 2004 and 2003, respectively.

H. Income Taxes

The Company is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also, under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including the Company, in the form of capital contributions. In 2005 and 2004, net capital contributions of $3.1 million and $1.0 million, respectively, were received by the Company under such provisions.

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

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

J. Environmental

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

K.Cash and Cash Equivalents

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

The Company receives refunds from its pipeline suppliers. Pursuant to an order of the NCUC, these funds must be segregated from the Company’s general funds and can be used for expansion projects or refunded to customers. The Company reports these amounts in restricted cash. On February 24, 2005, the NCUC authorized the Company to refund $7.7 million of restricted cash to customers by a direct bill credit in March 2005.

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L.New Accounting Standards

SFAS 154, “Accounting Changes and Error Corrections,” was issued in June 2005. It requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

Effective December 15, 2005, the Company adopted FIN 47, which was issued to clarify the term “conditional asset retirement” as used in SFAS 143. It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation 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 following table presents conditional asset retirement obligations and related assets as recorded in the Consolidated Balance Sheet as of December 31, 2005, and the proforma amounts that would have been recorded as of December 31, 2004 and 2003 had FIN 47 been adopted at the beginning of 2003.

	December 31,			December 31,			December 31,
	2005			2004			2003
Millions of dollars	Actual			Proforma			Proforma
Assets:
Within utility plant	$	5		$	5		$	5
Within accumulated depreciation		(2	)		(2	)		(2	)
Within other regulatory assets		10			10			9
Total	$	13		$	13		$	12
Liabilities:
Asset retirement obligation	$	13		$	13		$	12

Due to the regulated nature of the business for which conditional asset retirement obligations were recognized, the adoption of FIN 47 did not have an impact on the Company’s results of operations, cash flows or financial position for the year ended December 31, 2005. Proforma net income and earnings per share for the periods prior to the adoption of FIN 47 would not differ from amounts actually recorded during these periods. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:

Millions of dollars	2005		2004
Beginning balance		-		-
Adoption of FIN 47	$	13		-
Ending Balance	$	13		-

M.Related Party Transactions

The Company has related party transactions with its equity method investees. The Company records as cost of gas the storage and transportation costs charged by these investees. These costs totaled $15.8 million, $15.7 million and $16.5 million in 2005, 2004 and 2003, respectively. The Company owed these investees $1.3 million at December 31, 2005, 2004 and 2003. The Company received cash distributions from equity investees of $4.7 million, $4.7 million and $4.9 million during 2005, 2004 and 2003, respectively.

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Summarized combined financial information of unconsolidated affiliates as of and for the years ended December 31, 2005, 2004 and 2003, is presented below:

	2005		2004		2003
	Millions of dollars
Current assets	$	19	$	17	$	22
Non-current assets		179		185		190
Current liabilities		12		11		14
Non-current liabilities		76		83		89
Revenues		35		35		36
Gross profit		35		35		36
Income before income taxes		18		18		18

During the years ended December 31, 2005, 2004 and 2003, the Company had sales to an affiliate for natural gas and transportation services of approximately $17 million, $6 million and $3 million, respectively.

At December 31, 2005 an affiliate owed the Company $2.0 million for natural gas and transportation services. Additionally, the Company owed an affiliate $0.2 million related to billing and collection services for the sale of energy-related products and service contracts.

N. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

O.Use of Estimates

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

2.RATE AND OTHER REGULATORY MATTERS

The Company’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. The Company 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 the Company’s gas purchasing practices annually.

The Company’s benchmark cost of gas in effect during 2005 and 2004 was as follows:

Rate Per Therm	Effective Date
$.600	January-September 2004
$.675	October-November 2004
$.825	December 2004-January 2005
$.725	February-July 2005
$.825	August-September 2005
$1.10	October 2005
$1.275	November-December 2005

Since January 1, 2006, the NCUC has approved two decreases in the Company’s benchmark cost of gas, from $1.075 per therm to $.825 per therm for service rendered on and after March 1, 2006.

In November 2005, the NCUC authorized an amendment to the Company’s Rider D rate mechanism allowing recovery of certain uncollectible expenses related to gas cost. This change was effective December 1, 2005.

In September 2005, in connection with the Company’s 2005 Annual Prudence Review, the NCUC determined that the Company’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2005. The NCUC also authorized new rate decrements, effective October 1, 2005, to refund over-collections of certain gas costs included in deferred accounts.

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A state expansion fund, established by the North Carolina General Assembly and funded by refunds from the Company’s interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In September 2005, the NCUC approved the Company’s request for disbursement of up to $1.1 million from the expansion fund to extend natural gas service to Louisburg, North Carolina. The project is expected to be completed in 2006.

Effective November 1, 2004, the NCUC authorized the Company to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation’s Pipeline Integrity Management requirements.

3.EMPLOYEE BENEFIT PLANS

The Company participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA’s pension plan benefits for employees of the Company are calculated using a cash balance formula under which employees earn benefits through monthly compensation and interest credits. 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. The Company also participates in SCANA’s plan to provide certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost and are provided life insurance benefits at no charge. The cost of postretirement benefits other than pensions are accrued during the years the employees render the service necessary to be eligible for the applicable benefits.

For the years ended December 31, 2005 and 2004, the Company’s net periodic benefit cost was $1.5 million and $1.4 million, respectively, for the pension plan, and net periodic benefit cost was $2.9 million and $3.3 million, respectively, for the postretirement plan.

4.LONG-TERM DEBT

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

	Weighted-Average	Maturity	December 31,
	Interest Rate	Date	2005	2004
			Millions of dollars
Medium-Term Notes (unsecured)	6.63%	2011	$150	$150
Senior Debentures(a)	7.50%	2006-2026	122	126
Fair value of interest rate swaps			1	1
Total debt			273	277
Current maturities of long-term debt			(3)	(3)
Total long-term debt			$270	$274

(a)Includes $22.4 million and $25.6 million of fixed rate debt hedged by a variable interest rate swap for 2005 and 2004, respectively.

Annual amounts of long-term debt maturities are $3.2 million for each of the years 2006 through 2010.

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5.LINES OF CREDIT AND SHORT-TERM BORROWINGS

	2005			2004
	Millions of dollars
Committed lines of credit (total and unused)	$	125.0		$	125.0
Short-term borrowings outstanding:
Commercial paper (270 or fewer days)	$	98.6		$	57.8
Weighted average interest rate		4.47	%		2.47	%

The Company pays fees to banks as compensation for maintaining committed lines of credit. All commercial paper borrowings are supported by five-year revolving credit facilities which will expire on June 30, 2010.

6.INCOME TAXES

Total income tax expense attributable to income for 2005, 2004 and 2003 is as follows:

	2005			2004			2003
	Millions of dollars
Current taxes:
Federal	$	10.2		$	3.2		$	12.1
State		1.5			2.5			3.3
Total current taxes		11.7			5.7			15.4
Deferred taxes, net:
Federal		5.3			9.1			4.0
State		1.8			0.1			-
Total deferred taxes		7.1			9.2			4.0
Investment tax credit amortization		(0.3	)		(0.3	)		(0.3	)
Total income tax expense	$	18.5		$	14.6		$	19.1

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

	2005			2004			2003
	Millions of dollars
Income	$	25.7		$	23.7		$	30.9
Income tax expense		18.5			14.6			19.1
Total pre-tax income	$	44.2		$	38.3		$	50.0
Income taxes on above at statutory federal income tax rate	$	15.5		$	13.4		$	17.5
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)		2.1			1.7			2.2
Amortization of federal investment tax credits		(0.3	)		(0.3	)		(0.3	)
Other differences, net		1.2			(0.2	)		(0.3	)
Total income tax expense	$	18.5		$	14.6		$	19.1

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The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $107.3 million at December 31, 2005 and $100.7 million at December 31, 2004 (see Note 1H) are as follows:

	2005		2004
	Million of dollars
Deferred tax assets:
Nondeductible reserves	$	2.7	$	2.4
Other		4.7		5.4
Total deferred tax assets		7.4		7.8
Deferred tax liabilities:
Property, plant and equipment		95.3		94.5
Other		19.4		14.0
Total deferred tax liabilities		114.7		108.5
Net deferred tax liability	$	107.3	$	100.7

7.FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2005 and 2004 were as follows:

	2005		2004
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
	Millions of dollars
Long-term debt	272.8	309.8	276.8	327.0

Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. The carrying values reflect the fair values of derivatives designated as hedges under SFAS 133 criteria (interest rate swaps) based on settlement values obtained from counterparties. Early settlement of long-term debt may not be possible or may not be considered prudent.

The Company’s hedging program for natural gas purchases is designed to reduce price volatility to firm customers. In an October 2003 order, the NCUC declared the program was reasonable. Transaction fees and any realized and unrealized gains or losses are recorded in deferred accounts. As of December 31, 2005 the Company had deferred net realized gains of approximately $9.3 million and net deferred unrealized gains of $1.8 million.

The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable and receive fixed interest payments and are designated as fair value hedges of certain debt instruments. The fair value of interest rate swaps is recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. At December 31, 2005, the estimated fair value of the Company’s swap was $0.4 million related to a notional amount of $22.4 million.

8. COMMITMENTS AND CONTINGENCIES

A. Environmental

The Company is responsible for environmental cleanup at five sites in North Carolina on which manufactured gas plant (MGP) residuals are present or suspected. The Company's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. The Company has recorded a liability and associated regulatory asset of $7.4 million, which reflects its estimated remaining liability at December 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are $3.1 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

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B. Claims and Litigation

The Company is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.

C. Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2019. Amounts expended for gas supply, transportation, storage and other commitments totaled $541.0 million, $402.0 million and $288.4 million in 2005, 2004 and 2003, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2006		$	463.3
2007			57.2
2008			55.3
2009			59.6
2010			55.2
Thereafter			228.2
Total		$	918.8

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 purchase obligations without penalty.

9. SEGMENT OF BUSINESS INFORMATION

Gas Distribution is comprised of the Company's local distribution operations, and operating income is used to measure its profitability. The All Other segment is comprised solely of the Company's two equity method investees. One investee owns a 105-mile gas transmission pipeline, and the other owns a liquefaction, storage and regasification facility. Both investees are located in North Carolina. Net income is used to measure profitability for the All Other segment. The Company did not have intersegment revenue for any period reported.

Disclosure of Reportable Segments (Millions of dollars)

2005	Gas Distribution	All Other	Adjustments/ Eliminations	Consolidated Total
External Revenue	$660	-	-	$660
Depreciation and Amortization	35	-	-	35
Operating Income	59	n/a	-	59
Net Income	n/a	-	$26	26
Interest Expense	21	-	-	21
Segment Assets	1,194	$28	76	1,298
Expenditures for Assets	64	-	-	64
Deferred Tax Assets	-	-	-	-

2004	Gas Distribution	All Other	Adjustments/ Eliminations	Consolidated Total
External Revenue	$516	-	-	$516
Depreciation and Amortization	34	-	-	34
Operating Income	53	n/a	-	53
Net Income	n/a	-	$24	24
Interest Expense	21	-	-	21
Segment Assets	1,091	$28	69	1,188
Expenditures for Assets	50	-	-	50
Deferred Tax Assets	1	-	-	1

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2003	Gas Distribution	All Other	Adjustments/ Eliminations	Consolidated Total
External Revenue	$509	-	-	$509
Depreciation and Amortization	34	-	-	34
Operating Income	63	n/a	-	63
Net Income	n/a	-	$31	31
Interest Expense	21	-	-	21
Segment Assets	1,067	$28	57	1,152
Expenditures for Assets	48	-	-	48
Deferred Tax Assets	3	-	-	3

10. QUARTERLY FINANCIAL DATA (UNAUDITED)

2005 Millionsof dollars	First Quarter		Second Quarter			Third Quarter			Fourth Quarter		Annual
Total operating revenues	$	246	$	84		$	60		$	270	$	660
Operating income (loss)		43		1			(4	)		19		59
Net income (loss)		24		(2	)		(6	)		10		26

2004 Millionsof dollars	First Quarter		Second Quarter			Third Quarter			Fourth Quarter		Annual
Total operating revenues	$	226	$	69		$	53		$	168	$	516
Operating income (loss)		42		(3	)		(6	)		20		53
Net income (loss)		23		(4	)		(6	)		11		24

148

PART II, ITEMS 9 AND 9A, PART III AND PART IV

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

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

Not Applicable.

ITEM 9A. CONTROLS AND PROCEDURES

SCANA:

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2005, 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 the Company's disclosure controls and procedures. 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, 2005. There has been no change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2005 that has materially affected or is reasonably likely to materially affect SCANA's internal control over financial reporting.

Management's Evaluation of Internal Control Over Financial Reporting:

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed the effectiveness of such structure and procedures. This management report follows.

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCANA Corporation (SCANA) is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA's internal control system was designed to provide reasonable assurance to SCANA's management and board of directors regarding the preparation and fair presentation of published financial statements.

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, 2005. 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, 2005, internal control over financial reporting is effective based on those criteria.

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

March 1, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

SCANA Corporation

We have audited management's assessment, included in the accompanying Management Report On Internal Control Over Financial Reporting, that SCANA Corporation and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

In our opinion, management's assessment that SCANA Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, SCANA Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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, 2005, of SCANA Corporation and subsidiaries and our report dated March 1, 2006, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/DELOITTE & TOUCHE LLP

Columbia, South Carolina

March 1, 2006

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SCE&G:

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2005, 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. 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, 2005. There has been no change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2005 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting.

PSNC Energy:

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2005, an evaluation was performed under the supervision and with the participation of PSNC Energy's management, including the CEO and CFO, of the effectiveness of the design and operation of PSNC Energy's disclosure controls and procedures. Based on that evaluation, PSNC Energy's management, including the CEO and CFO, concluded that PSNC Energy's disclosure controls and procedures were effective as of December 31, 2005. There has been no change in PSNC Energy's internal controls over financial reporting during the quarter ended December 31, 2005 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

152

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

SCANA: A list of SCANA's executive officers is in Part I of this annual report at page 26. 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 2006 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA's fiscal year.

CODE OF ETHICS

SCE&G: SCE&G subscribes to the Code of Ethics of SCANA Corporation. All employees (including the Chief Executive Officer, Chief Financial Officer and Controller), and directors are required to abide by SCANA's Code of Conduct & Ethics (the "Code") to ensure that SCANA's business is conducted in a consistently legal and ethical manner. The Code forms the foundation of a comprehensive process that includes compliance with corporate policies and procedures, an open relationship among colleagues that contributes to good business conduct, and an abiding belief in the integrity of SCANA's employees. SCANA's policies and procedures cover all areas of business conduct, and require adherence to all laws and regulations applicable to the conduct of SCANA's business.

The full text of the Code is published on the SCANA website, at www.scana.com, under the "Investor Information - Code of Conduct & Ethics" caption, and a copy is also available in print upon request to the Corporate Secretary, SCANA Corporation, Mail Code 13-4, 1426 Main Street, Columbia, South Carolina 29201. SCANA intends to disclose future amendments to, or waivers from, certain provisions of the Code on its website within two business days following the date of such amendment or waiver.

DIRECTORS

The directors listed below were elected May 5, 2005 (except as otherwise indicated) to hold office until the next annual meeting of SCE&G's shareholders to be held on April 27, 2006.

Name and Year First Became Director	Age	Principal Occupation; Directorships
Bill L. Amick (1990)	62	For more than five years, Chairman of the Board of Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., Batesburg, SC (vertically integrated broiler operation).
		Director, SCANA Corporation; PSNC Energy; Blue Cross and Blue Shield of South Carolina.
James A. Bennett (1997)	44	Since August 2002, Executive Vice President and Director of Public Affairs, First Citizens Bank, Columbia, SC.
		From May 2000 to July 2002, President and Chief Executive Officer of South Carolina Community Bank, Columbia, SC.
		Director, SCANA Corporation; PSNC Energy.
William C. Burkhardt* (2000)	68	Since May 2004, Chairman and Chief Executive Officer of Titan Holdings, LLC, Raleigh, NC (real estate investment company).
		From October 2003 until his May 2004 retirement, Chief Executive Officer of Capital Bank, Raleigh, NC.
		From May 2000 until October 2003 Mr. Burkhardt pursued personal interests.
		From 1980 until his May 2000 retirement, President and Chief Executive Officer of Austin Quality Foods, Inc., Cary, NC (production and distribution company of baked snacks for the food industry).
		Director, SCANA Corporation; PSNC Energy; Capital Bank, Raleigh, NC and Plaza Belmont II, Kansas City, MO.

Sharon A. Decker (2005)	48	Elected to the Board on December 20, 2005. Since September 2004, Founder and principal of The Tapestry Group LLC, Rutherfordton, NC (motivational speaking company).
		From August 1999 to September 2004 President of Tanner Holdings and Doncaster, Rutherfordton, NC (apparel manufacturers).
		Director, SCANA Corporation; PSNC Energy; Coca-Cola Bottling Company Consolidated, Inc., Charlotte, NC and Family Dollar Stores, Inc., Charlotte, NC.

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D. Maybank Hagood* (1999)	44	For more than five years, President and Chief Executive Officer of William M. Bird and Company, Inc. (wholesale distributor of floor covering materials) and its subsidiary Southern Diversified Distributors, LLC, (provider of logistics services) both in Charleston, SC.
		Director, SCANA Corporation; PSNC Energy.
W. Hayne Hipp (1983)	65	Mr. Hipp is a private investor. Prior to it’s acquisition in January 2006, Mr. Hipp was Chairman , Chief Executive Officer and a director of The Liberty Corporation, Greenville, SC. (a broadcasting holding company). Mr. Hipp held these positions for more than five years.
		Director, SCANA Corporation; PSNC Energy.
Lynne M. Miller* (1997)	54	Since August 2005, Senior Business Consultant to Quanta Capital Holdings, Inc., Reston, VA (a specialty insurer).
		From April 2004 through July 2005, President of Quanta Technical Services LLC., Reston VA.
		From September 2003 through March 2004, Chief Executive Officer of Environmental Strategies Consulting, LLC, a division of Quanta Technical Services LLC. Ms. Miller co-founded Environmental Strategies Corporation (an environmental consulting firm) and served as President from 1986 until 1995 and as Chief Executive Officer from 1995 until September 2003 when the firm was acquired by Quanta Capital Holdings, Inc. and its name was changed to Environmental Strategies Consulting LLC.
		Director, SCANA Corporation; PSNC Energy; Adams National Bank (a subsidiary of Abigail Adams National Bancorp, Inc.), Washington, DC.
Maceo K. Sloan* (1997)	56	For more than five years, Chairman, President and Chief Executive Officer of Sloan Financial Group, Inc. (financial holding company) and Chairman, Chief Executive Officer and Chief Investment Officer of both NCM Capital Management Group, Inc. and NCM Capital Advisers, Inc. (investment management companies), Durham, NC.
		Director, SCANA Corporation; PSNC Energy; M&F Bancorp, Inc. and its subsidiary, Mechanics and Farmers Bank; and Trustee of Teachers Insurance Annuity Association-College Retirement Equity Fund and (TIAA-CREF) funds boards, Durham, NC.

Harold C. Stowe* (1999)	59	Since February 2005 retired as President of Canal Holdings, LLC, Conway, SC (forest products industry company).
		For more than five years, President of Canal Holdings, LLC and its predecessor company, Conway, SC (forest products industry company).
		Director, SCANA Corporation; PSNC Energy; New South Companies, Inc., Charlotte, NC; Ruddick Corporation, Charlotte, NC.

William B. Timmerman (1991)	59	For more than five years, Chairman of the Board, President and Chief Executive Officer of SCANA Corporation, Columbia, SC.
		Director, SCANA Corporation; PSNC Energy.
G. Smedes York (2000)	65	For more than five years, President and Treasurer of York Properties, Inc., Raleigh, NC. (full-service commercial and residential real estate company). Chairman of the Board of York Simpson Underwood (residential brokerage company) and McDonald-York, Inc. (general contractor) both in Raleigh, NC.
		Director, SCANA Corporation; PSNC Energy.

* Indicates a member of the Audit Committee of SCE&G's Board of Directors. Mr. Stowe has been determined by SCE&G's board of directors to be an audit committee financial expert within the meaning of Item 401(h) of Regulation S-K. SCE&G's board of directors has also determined that Mr. Stowe is independent, as that term is used in Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.

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EXECUTIVE OFFICERS

SCE&G's officers are elected at the annual organizational meeting of the Board of Directors and hold office until the next such organizational meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted.

Name	Age	Positions Held During Past Five Years	Dates
W. B. Timmerman	59	Chairman of the Board and Chief Executive Officer	*-present
J. C. Bouknight	53	Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA	2004-present *-2004
S. D. Burch	48	Senior Vice President, Fuel Procurement and Asset Management Deputy General Counsel and Assistant Secretary	2003-present *-2003
S. A. Byrne	46	Senior Vice President-Generation, Nuclear and Fossil Hydro Senior Vice President-Nuclear Operations	2004-present *-2004
P. V. Fant	52	Senior Vice President Transmission Services President and Chief Operating Officer-SCPC and SCG Pipeline Executive Vice President-SCPC Executive Vice President-SCG Pipeline, Inc.	2004-present 2004-present *-2004 2002-2004
N. O. Lorick	55	President and Chief Operating Officer	*-present
K. B. Marsh	50	Senior Vice President and Chief Financial Officer Controller	*-present
F. P. Mood, Jr.	68	Senior Vice President, General Counsel and Assistant Secretary Attorney, Haynsworth Sinkler Boyd, P.A.	2005-present *-2005

* Indicates position held at least since March 1, 2001

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

All of SCE&G's common stock is held by its parent, SCANA Corporation. The required forms indicate that no equity securities of SCE&G are owned by its directors and officers. Based solely on a review of the copies of such forms and amendments furnished to SCE&G and written representations from the officers and directors, SCE&G believes that its officers, directors and greater than 10% beneficial owners complied with all applicable Section 16(a) filing requirements during 2005.

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ITEM 11. EXECUTIVE COMPENSATION

SCANA: The information called for by Item 11, Executive Compensation, is incorporated herein by reference to the captions "Director Compensation," "Compensation Committee Interlocks and Insider Participation," and "Executive Compensation" in SCANA's definitive proxy statement for the 2006 annual meeting of shareholders.

SCE&G: The information called for by Item 11, Executive Compensation, is as follows:

Summary Compensation Table

		Annual Compensation			Long-Term Compensation Awards
Name and Principal Position	Year	Salary ($)		Bonus (1) ($)	Securities Underlying Option/ SARS (#)	LTIP Payouts (2) ($)	All Other Compensation (3) ($)
W. B. Timmerman	2005	997,654	(4)	1,278,443	-	1,509,703	124,560
Chairman, President and	2004	931,583		948,494	-	-	108,828
Chief Executive Officer- SCANA	2003	858,219		718,493	-	1,150,242	102,904
N. O. Lorick	2005	498,077		487,500	-	535,875	60,674
President and Chief Operating	2004	470,833		378,625	-	-	55,324
Officer-SCE&G	2003	419,808		300,036	-	325,384	50,219
K. B. Marsh	2005	498,077		487,500	-	535,875	53,884
Senior Vice President and Chief	2004	470,833		378,625	-	-	48,534
Financial Officer-SCANA	2003	419,808		300,036	-	325,384	45,185
S. A. Byrne	2005	399,216		300,300	-	296,099	48,909
Senior Vice President-	2004	362,728		225,660	-	-	33,366
Generation, Nuclear and Fossil	2003	323,351		180,675	-	169,634	30,993
Hydro-SCE&G
J. C. Bouknight	2005	286,184		195,750	-	-	24,921
Senior Vice President, Human	2004	170,769		129,200	-	-	42,978
Resources - SCANA	2003	-		-	-	-	-

(1)Payments under the Annual Incentive Plan.

(2)Payouts of performance share awards under the Long-Term Equity Compensation Plan.

(3) All other compensation for the named executive officers consists of matching contributions to defined contribution plans and life insurance premiums on policies owned by named executive officers. The following are premium amounts for 2005: Messrs. Timmerman - $7,791; Byrne - $0; Lorick - $8,072; Marsh - $1,282 and Bouknight - $0. The following are matching contribution amounts for 2005: Messrs. Timmerman - $116,769, Byrne - $48,909; Lorick - $52,602; Marsh - $52,602 and Bouknight - $24,921.

(4)Reflects actual salary earned in 2005. Base salary of $1,002,700 became effective on February 17, 2005.

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Option Exercises, Outstanding Options and Related Information

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

(a)	(b)	(c)	(d)	(e)
			Number of Securities Underlying Unexercised Option/SARs At FY-End (#)	Value of Unexercised In-the-Money Options/ SARs at FY-End ($)(2)
Name	Shares Acquired On Exercise (#)	Value Realized ($) (1)	Exercisable/ Unexercisable	Exercisable/ Unexercisable
W. B. Timmerman	-	-	123,067/0	1,459,757/0
N. O. Lorick	25,939	295,185	0/0	0/0
K. B. Marsh	25,939	297,779	0/0	0/0
S. A. Byrne	27,938	317,369	42,992/0	509,885/0
J. C. Bouknight	-	-	-	-

⁽¹⁾The difference between the exercise prices paid and the closing price of SCANA Common Stock on the exercise dates.

⁽²⁾Based on the closing price of $39.38 per share on December 30, 2005, the last trading day of the fiscal year,and exercise  

     prices ranging from $27.45 to $29.60 per share.

Long-Term Incentive Plans Awards

The following table lists the performance share awards made in 2005 (for potential payment in 2008) under the Long-Term Equity Compensation Plan and estimated future payouts under that plan at threshold, target and maximum levels for each of the executive officers included in the Summary Compensation Table.

LONG-TERM INCENTIVE PLANS

AWARDS IN LAST FISCAL YEAR

			Estimated Future Payouts Under Non-Stock Price-Based Plans
Name	Number of Shares, Units or Other Rights (#)	Performance or Other Period Until Maturation or Payout	Threshold (#)	Target (#)	Maximum (#)
W. B. Timmerman	71,558	2005-2007	35,779	71,558	107,337
N. O. Lorick	22,302	2005-2007	11,151	22,302	33,453
K. B. Marsh	22,302	2005-2007	11,151	22,302	33,453
S. A. Byrne	12,144	2005-2007	6,072	12,144	18,216
J. C. Bouknight	7,244	2005-2007	3,622	7,244	10,866

Payouts of performance share awards will be dictated by SCANA’s performance against pre-determined measures of total shareholder return and earnings per share over the three-year plan cycle.

Sixty percent of target performance share awards are based on SCANA’s total shareholder return (“TSR”) over the three-year plan cycle compared with a peer group. TSR is calculated by dividing stock price increase over the three-year period, plus cash dividends, by the stock price as of the beginning of the period. Payouts vary according to SCANA’s ranking against the peer group. No payout is earned if performance is less than the 33^rd percentile. Executives earn threshold payouts (50% of target award) if SCANA ranks at the 33^rd percentile in relation to the peer group’s three-year TSR performance. Target payouts (100% of target award) occur if SCANA ranks at the 50^th percentile in relation to the peer group’s three-year TSR performance. Maximum payouts (150% of target award) result if SCANA’s performance ranks at or above the 75^th percentile in relation to the peer group’s three-year performance.

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Forty percent of target performance share awards are based on meeting SCANA’s goals for three-year growth in earnings per share (“EPS”) from ongoing operations. Payouts vary according to goal achievement. No payout is earned if EPS growth is less than the minimum of the pre-established growth range goal. Executives earn threshold payouts (50% of target award) upon achievement of minimum three-year EPS growth projection. Target payouts (100% of target award) occur if SCANA achieves the targeted three-year EPS growth projection. Maximum payouts (150% of target award) result if SCANA’s performance is at or above the maximum three-year EPS growth projection.

Payments are calculated using a sliding scale for performance between threshold and target and target and maximum levels. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA’s discretion.

Defined Benefit Plans

SCANA sponsors a tax qualified defined benefit retirement plan (the "Retirement Plan") in which employees of its subsidiaries participate. The plan utilizes a mandatory cash balance benefit formula for employees hired on or after January 1, 2000. Effective July 1, 2000, SCANA employees hired prior to January 1, 2000 were given the choice of remaining under the Retirement Plan's final average pay formula or switching to the cash balance formula. All the executive officers named in the Summary Compensation Table participate under the cash balance formula of the plan.

The cash balance formula is expressed in the form of a hypothetical account balance. Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances is determined annually and is equal to the average rate for 30-year Treasury Notes for December of the previous calendar year. Compensation credits equal 5% of compensation under the Social Security wage base and 10% of compensation in excess of the Social Security wage base.

In addition to its Retirement Plan for all employees, SCANA provides Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees, including officers. A SERP is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations.

The estimated annual retirement benefits payable as life annuities at age 65 under the Retirement Plan and SERPs, based on projected compensation (assuming increases of 4% per year), to the executive officers named in the Summary Compensation Table are as follows: Mr. Timmerman-$464,640; Mr. Lorick-$297,456; Mr. Marsh-$368,232; Mr. Byrne-$299,820 and Mr. Bouknight-$77,520.

Termination, Severance and Change in Control Arrangements

SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust is to help retain and attract quality leadership in key SCANA positions. The trust holds SCANA contributions (if made) which may be used to pay the deferred compensation benefits of certain directors, executives and other key employees of SCANA and its subsidiaries in the event of a Change in Control (as defined in the trust). The current executive officers included in the Summary Compensation Table participate in all the plans listed below which are covered by the trust.

(1)SCANA Corporation Executive Deferred Compensation Plan

(2)SCANA Corporation Supplemental Executive Retirement Plan

(3)SCANA Corporation Long-Term Equity Compensation Plan

(4)SCANA Corporation Short-Term Annual Incentive Plan

(5)SCANA Corporation Key Executive Severance Benefits Plan

(6)SCANA Corporation Supplementary Key Executive Severance Benefits Plan

The Key Executive Severance Benefits Plan and each of the plans listed at (1) through (4) provide for payment of benefits in a lump sum to the eligible participants immediately upon a Change in Control, unless the Key Executive Severance Benefits Plan is terminated prior to the Change in Control. In contrast, the Supplementary Key Executive Severance Benefits Plan is operative for a period of 24 months following a Change in Control in which the Key Executive Severance Benefits Plan is inoperative because it was terminated before the Change in Control. The Supplementary Key Executive Severance Benefits Plan provides benefits in lieu of those otherwise provided under plans (1) through (4) if: (i) the participant is involuntarily terminated from employment without "Just Cause," or (ii) the participant voluntarily terminates employment for "Good Reason" (as these terms are defined in the Supplementary Key Executive Severance Benefits Plan).

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Benefit distributions relative to a Change in Control, as to which either the Key Executive Severance Benefits Plan or the Supplementary Key Executive Severance Benefits Plan is operative, include an amount equal to estimated federal, state and local income taxes and any estimated applicable excise taxes owed by plan participants on those benefits.

The benefit distributions under the Key Executive Severance Benefits Plan would include the following three benefits:

·   An amount equal to three times the sum of: (i) the participant's annual base salary in effect as of the date of the Change in Control and (ii) the officer's target annual incentive award in effect as of the date of the Change in Control under the Short-Term Annual Incentive Plan.

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·   An amount equal to the projected cost for medical, long-term disability and certain life insurance coverage for three years following the Change in Control as though the participant had continued to be a SCANA employee.

·   An amount equal to the participant's Supplemental Executive Retirement Plan benefit accrued to the date of the Change in Control, increased by the present value of projected benefits that would otherwise accrue under the plan (based on the plan's actuarial assumptions) assuming that the participant remained employed until reaching age 65, and offset by the value of the participant's Retirement Plan benefit.

Additional benefits payable upon a Change in Control in which the Key Executive Severance Benefits Plan is operable are as follows:

·   A benefit distribution of all amounts credited to the participant's Executive Deferred Compensation Plan account as of the date of the Change in Control.

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

·   Under the Long-Term Equity Compensation Plan, all nonqualified stock options awarded would become immediately exercisable and remain exercisable throughout their original term.

·   A benefit distribution under the Short-Term Annual Incentive Plan equal to 100% of the target award in effect as of the date of the Change in Control.

The benefits and their respective amounts under the Supplementary Key Executive Severance Benefits Plan would be the same as those described above, except that the benefits payable with respect to the Executive Deferred Compensation Plan would be increased by the prime rate published in the Wall Street Journal most nearly preceding the date of the Change in Control plus 3% calculated until the end of the month preceding the month in which the benefits are distributed.

Compensation Committee Interlocks and Insider Participation

During 2005, decisions on various elements of executive compensation were made by the Human Resources Committee. No officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Human Resources Committee.

The names of the persons who serve on the Human Resources Committee can be found at Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Director Compensation

Board Fees

The Board reviews Director compensation annually with guidance from the Nominating and Governance Committee. In making its recommendations, the committee is required by SCANA’s Governance Principles to consider that compensation should fairly pay Directors for work required in a company of SCANA’s size and scope, compensation should align Directors’ interests with the long-term interests of shareholders, and the compensation structure should be transparent and easy for shareholders to understand.

Officers who are also Directors do not receive additional compensation for their service as Directors. All Directors of SCANA also serve as Directors of SCE&G without additional compensation. Effective January 1, 2005, compensation for non-employee Directors consists of the following:

·   an annual retainer of $45,000;

·   a fee of $6,500 for attendance at a regular quarterly meeting of the board of directors;

·   a fee of $6,000 for attendance at all-day meetings of the board of directors other than regular meetings;

·   a fee of $3,000 for attendance at a committee meeting held on a day other than a day a regular meeting of the Board is held;

·   a fee of $3,000 for attendance at half day meetings of the board other than regular meetings;

·   a fee $300 for telephonic meetings of the board of directors or a committee that last fewer than 30 minutes;

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·   a fee of $600 for telephonic meetings of the board of directors or a committee that last more than 30 minutes; and

·   reimbursement of reasonable expenses incurred in connection with all of the above.

Director Compensation and Deferral Plans

Since January 1, 2001, non-employee director compensation and deferrals have been governed by the SCANA Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2005, the only director remaining in the Voluntary Deferral Plan was Mr. Bennett, whose account was credited with interest of $4,345.26 for the year.

Under the Director Compensation and Deferral Plan, a director may elect to defer the annual retainer fee, which (effective January 1, 2006) is required to be paid in 100% SCANA common stock, in a hypothetical investment in SCANA common stock, with distribution from the plan to be ultimately payable in actual shares of SCANA common stock. A director also may elect to defer up to 100% of meeting attendance and conference fees with distribution from the plan to be ultimately payable in either SCANA common stock or cash. Amounts payable in SCANA common stock accrue earnings during the deferral period at SCANA's dividend rate, which amount may be elected to be paid in cash when accrued or retained to invest in additional hypothetical shares of SCANA common stock. Amounts payable in cash accrue interest until paid.

During 2005, Messrs. Amick, Bennett, Burkhardt, Sloan and York and Ms. Miller elected to defer 100% of their compensation and earnings under the Director Compensation and Deferral Plan so as to acquire hypothetical shares of SCANA common stock.

Other Director Compensation

  During 2005 the Company provided William B. Bookhart, Jr., (deceased November 21, 2005) and his wife with health care benefits having a value of $5,773 in excess of Mr. Bookhart's contribution.  No other non-management directors received health care benefits from the Company in 2005.

Endowment Plan

Upon election to a second term, a director becomes eligible to participate in the SCANA Director Endowment Plan, which provides for SCANA to make tax deductible, charitable contributions totaling $500,000 to institutions of higher education designated by the director. The plan is intended to reinforce SCANA's commitment to quality higher education and to enhance its ability to attract and retain qualified Board members. A portion is contributed upon retirement of the director and the remainder upon the director's death. The plan is funded in part through insurance on the lives of the directors.

Designated institutions of higher education in South Carolina, North Carolina and Georgia must be approved by SCANA's Chief Executive Officer. Institutions in other states must be approved by the Human Resources Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the plan.

161

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

SCANA: Information called for by this Item is incorporated herein by reference to the caption "Share Ownership of Directors, Nominees and Executive Officers" and "Five Percent Ownership of SCANA Common Stock" in SCANA's definitive proxy statement for the 2006 annual meeting of shareholders.

Equity securities issuable under SCANA's compensation plans at December 31, 2005 are summarized as follows:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstandingoptions, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders:
Long-Term Equity Compensation Plan	432,970	$27.53	3,210,827
Non-Employee Director Compensation Plan	n/a	n/a	122,566
Equity compensation plans not approved by security holders	n/a	n/a	n/a
Total	432,970	$27.53	3,333,393

SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The following table lists shares of SCANA common stock beneficially owned on February 22, 2006 by each director and each person named in the Summary Compensation table in Item 11, Executive Compensation.

162

SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

Name	Amount and Nature of Beneficial Ownership of SCANA Common Stock*(1)(2)(3)(4)(5)	Name	Amount and Nature of Beneficial Ownership of SCANA Common Stock*(1)(2)(3)(4)(5)
B. L. Amick (6)	11,016	N. O. Lorick	19,513
J. A. Bennett (6)	2,603	K. B. Marsh	18,633
J. C. Bouknight	553	L. M. Miller	3,666
W. C. Burkhardt (6)	13,121	M. K. Sloan (6)	1,831
S. A. Byrne	51,916	H. C. Stowe	2,732
S. A. Decker	1,112	W. B. Timmerman	181,441
D. M. Hagood (6)	1,540	G. S. York	13,204
W. H. Hipp	14,058

Directors and Executive Officers as a group

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

All directors and executive officers as a group (18 persons) total 539,295 shares, including 166,059 shares subject to currently exercisable options. Total percent of class outstanding is less than one percent.

(1) Includes 182 shares owned by close relatives of Mr. Lorick.

(2) Includes shares purchased through February 22, 2006, by the Trustee under SCANA's Stock Purchase Savings Plan.

(3) Hypothetical shares acquired under the SCANA Director Compensation and Deferral Plan are not included in the above table. As of February 3, 2006, each of the following directors had acquired under the plan the number of hypothetical shares following his or her name: Messrs. Amick -13,091; Bennett -13,171; Burkhardt -16,074; Hagood - 4,089; Hipp - 11,527; Sloan - 14,490; Stowe - 11,538; York - 14,750; Ms. Decker - 0 and Ms. Miller - 15,357.

(4) Includes shares subject to options that are currently exercisable or that will become exercisable within 60 days in the following amounts: Messrs. Timmerman-123,067; and Byrne-42,992.

(5) Hypothetical shares acquired under the SCANA Executive Deferred Compensation Plan are not included in the above table. As of February 3, 2006, each of the following officers had acquired under the plan, the number of hypothetical shares following his or her name: Messrs. Timmerman-37,654; Lorick-9,176; Marsh-4,946; and Byrne-6,025.

(6) Indicates a member of the Human Resources Committee.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Not Applicable

163

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

SCANA: The information required by Item 14 is incorporated herein by reference to "Proposal 2 - Approval of Appointment of Independent Registered Public Accounting Firm" in SCANA's definitive proxy statement for the 2006 annual meeting of shareholders.

SCE&G and PSNC Energy:

SCANA's Audit Committee Charter requires the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the independent registered accounting firm. Pursuant to a policy adopted by the Audit Committee, its chairman may pre-approve the rendering of services on behalf of the Audit Committee. Decisions to pre-approve the rendering of services by the chairman are presented to the Audit Committee at each of its scheduled meetings.

Independent Registered Public Accounting Firm’s Fees

The following table sets forth the aggregate fees billed to SCE&G and PSNC Energy for the fiscal years ended December 31, 2005 and 2004 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

	2005				2004
	SCE&G		PSNC Energy		SCE&G		PSNC Energy
Audit Fees(1)	$	1,389,564	$	268,441	$	1,380,354	$	284,512
Audit-Related Fees(2)		50,073		10,793		70,565		6,240
Tax Fees(3)		51,727		3,968		2,582		535
All Other Fees		-		-		-		-
Total Fees	$	1,491,364	$	283,202	$	1,453,501	$	291,287

(1) Fees for audit services billed in 2005 and 2004 consisted of audits of annual financial statements, comfort letters, statutory and regulatory audits, consents and other services related to Securities and Exchange Commission ("SEC") filings and accounting research.

(2) Fees primarily for employee benefit plan audits for 2005 and 2004.

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

In 2005 and 2004, all of the Audit Fees, Audit Related Fees and Tax Fees were approved by the Audit Committee.

164

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)The following documents are filed or furnished as a part of this Form 10-K:

(1)Financial Statements and Schedules:

The Report of Independent Registered Public Accounting Firm on the financial statements for SCANA, SCE&G and PSNC Energy are listed under Item 8 herein.

The financial statements and supplementary financial data filed as part of this report for SCANA, SCE&G and PSNC Energy are listed under Item 8 herein.

The financial statement schedules filed as part of this report for SCANA, SCE&G and PSNC Energy begin on the following page.

(2)Exhibits

Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.

Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA's employee stock purchase plan will be furnished under cover of Form 10-K/A to the Commission 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, of SCE&G, for itself and its consolidated affiliates, and of PSNC Energy, for itself and its subsidiaries, have been omitted and SCANA, SCE&G and PSNC Energy agree to furnish a copy of such instruments to the Commission upon request.

165

Schedule II—Valuation and Qualifying Accounts

	Additions
Description	Beginning Balance	Charged to Income	Charged to Other Accounts	Deductions from Reserves	Ending Balance
SCANA:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2005	15,740,636	26,705,178	-	17,581,989	24,863,825
2004	16,398,983	16,181,865	-	16,840,212	15,740,636
2003	16,749,601	15,998,233	-	16,348,851	16,398,983
Reserve for investment impairment
2005	-	-	-	-	-
2004	125,000	-	-	125,000	-
2003	4,477,050	125,000	-	4,477,050	125,000
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2005	8,121,122	6,038,014	-	7,830,775	6,328,361
2004	8,980,495	6,694,152	-	7,553,525	8,121,122
2003	7,067,466	6,368,705	-	4,455,676	8,980,495
SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2005	1,182,064	3,518,845	-	3,126,840	1,574,069
2004	951,176	2,891,370	-	2,660,482	1,182,064
2003	694,000	4,666,778	-	4,409,602	951,176
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2005	5,749,088	3,378,138	-	4,235,150	4,892,076
2004	6,339,466	4,300,548	-	4,890,926	5,749,088
2003	4,635,061	5,181,696	-	3,477,291	6,339,466
PSNC Energy:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2005	1,978,730	2,981,769	-	2,516,288	2,444,211
2004	2,230,423	2,323,547	-	2,575,240	1,978,730
2003	1,512,238	3,828,398	-	3,110,213	2,230,423
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2005	1,190,586	639,349	-	583,630	1,246,305
2004	1,404,157	1,073,433	-	1,287,004	1,190,586
2003	1,239,698	810,000	-	645,541	1,404,157

166

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

SCANA CORPORATION
BY:	/s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director
DATE:	March 1, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.

/s/W. B. Timmerman

W. B. Timmerman, Chairman of the Board,

President, Chief Executive Officer and Director (Principal Executive Officer)

/s/K. B. Marsh

K. B. Marsh, Senior Vice President

and Chief Financial Officer

(Principal Financial Officer)

/s/J. E. Swan, IV

J. E. Swan, IV, Controller

(Principal Accounting Officer)

Other Directors*:
	B. L. Amick	W. M. Hipp
	J. A. Bennett	L. M. Miller
	W. C. Burkhardt	M. K. Sloan
	S. A. Decker	H. C. Stowe
	D. M. Hagood	G. S. York

* Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact

DATE: March 1, 2006

167

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries or consolidated affiliates thereof.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY:	/s/N. O. Lorick N. O. Lorick President and Chief Operating Officer
DATE:	March 1, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries or consolidated affiliates thereof.

/s/W. B. Timmerman

W. B. Timmerman, Chairman of the Board,

Chief Executive Officer and Director

(Principal Executive Officer)

/s/K. B. Marsh

K. B. Marsh, Senior Vice President

and Chief Financial Officer

(Principal Financial Officer)

/s/J. E. Swan, IV

J. E. Swan, IV, Controller

(Principal Accounting Officer)

Other Directors*:
	B. L. Amick	W. M. Hipp
	J. A. Bennett	L. M. Miller
	W. C. Burkhardt	M. K. Sloan
	S. A. Decker	H. C. Stowe
	D. M. Hagood	G. S. York

* Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact

DATE: March 1, 2006

168

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
BY:	/s/D. R. Harris D. R. Harris President and Chief Operating Officer
DATE:	March 1, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.

/s/W. B. Timmerman

W. B. Timmerman, Chairman of the Board,

Chief Executive Officer and Director

(Principal Executive Officer)

/s/K. B. Marsh

K. B. Marsh, Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/J. E. Swan, IV

J. E. Swan, IV, Controller

(Principal Accounting Officer)

Other Directors*:
	B. L. Amick	W. M. Hipp
	J. A. Bennett	L. M. Miller
	W. C. Burkhardt	M. K. Sloan
	S. A. Decker	H. C. Stowe
	D. M. Hagood	G. S. York

* Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact

DATE: March 1, 2006

169

EXHIBIT INDEX

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	PSNC Energy	Description
3.01	X			Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X			Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03		X		Restated Articles of Incorporation of South Carolina Electric & Gas Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.04		X		Articles of Amendment effective as of the dates indicated below and filed as exhibits to the Registration Statements or Exchange Act reports set forth below and are incorporated by reference herein
				May 22, 2001	Exhibit 3.02	to Registration No. 333-65460
				June 14, 2001	Exhibit 3.04	to Registration No. 333-65460
				August 30, 2001	Exhibit 3.05	to Registration No. 333-101449
				March 13, 2002	Exhibit 3.06	to Registration No. 333-101449
				May 9, 2002	Exhibit 3.07	to Registration No. 333-101449
				June 4, 2002	Exhibit 3.08	to Registration No. 333-101449
				August 12, 2002	Exhibit 3.09	to Registration No. 333-101449
				March 13, 2003	Exhibit 3.03	to Registration No. 333-108760
				May 22, 2003	Exhibit 3.04	to Registration No. 333-108760
				June 18, 2003	Exhibit 3.05	to Registration No. 333-108760
				August 7, 2003	Exhibit 3.06	to Registration No. 333-108760
				May 18, 2004	Exhibit 3.05	to Form 10-Q for the quarter ended June 30, 2004
				June 18, 2004	Exhibit 3.06	to Form 10-Q for the quarter ended June 30, 2004
				August 12, 2004	Exhibit 3.05	to Form 10-Q for the quarter ended Sept. 30, 2004
				March 9, 2005	Exhibit 3.11	to Form 10-Q for the quarter ended Sept. 30, 2005
				May 16, 2005	Exhibit 3.12	to Form 10-Q for the quarter ended Sept. 30, 2005
				June 15, 2005	Exhibit 3.13	to Form 10-Q for the quarter ended Sept. 30, 2005
				August 16, 2005	Exhibit 3.14	to Form 10-Q for the quarter ended Sept. 30, 2005
3.05		X		Articles of Amendment dated February 26, 2004 (Filed as Exhibit 3.05 on Form 10-K for the year ended December 31, 2004.
3.06		X		Articles of Correction filed on June 1, 2001 correcting May 22, 2001 Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.07		X		Articles of Correction filed on February 17, 2004 correcting Articles of Amendment for the dates indicated below and filed as exhibits to the 2003 Form 10-K as set forth below and are incorporated by reference herein
				May 3, 2001	Exhibit 3.06
				May 22, 2001	Exhibit 3.07
				June 14, 2001	Exhibit 3.08
				August 30, 2001	Exhibit 3.09
				March 13, 2002	Exhibit 3.10
				May 9, 2002	Exhibit 3.11
				June 4, 2002	Exhibit 3.12

170

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	PSNC Energy	Description
				August 12, 2002	Exhibit 3.13
				March 13, 2003	Exhibit 3.14
				May 22, 2003	Exhibit 3.15
				June 18, 2003	Exhibit 3.16
				August 7, 2003	Exhibit 3.17
3.08	X			By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein)
3.09		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)
3.10			X	By-Laws of PSNC Energy as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-68516 and incorporated by reference herein)
4.01	X	X		Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)
4.02	X			Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein)
4.03	X	X		Indenture dated as of January 1, 1945, between the South Carolina Power Company and Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Filed as Exhibit 2-B to Registration Statement No. 2-26459 and incorporated by reference herein)
4.04	X	X		Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture (Exhibit 2-C to Registration Statement No. 2-26459 and incorporated by reference herein)
4.05	X	X		Fifth through Fifty-third Supplemental Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference herein
				December 1, 1950	Exhibit 2-D	to Registration No. 2-26459
				July 1, 1951	Exhibit 2-E	to Registration No. 2-26459
				June 1, 1953	Exhibit 2-F	to Registration No. 2-26459
				June 1, 1955	Exhibit 2-G	to Registration No. 2-26459
				November 1, 1957	Exhibit 2-H	to Registration No. 2-26459
				September 1, 1958	Exhibit 2-I	to Registration No. 2-26459
				September 1, 1960	Exhibit 2-J	to Registration No. 2-26459
				June 1, 1961	Exhibit 2-K	to Registration No. 2-26459
				December 1, 1965	Exhibit 2-L	to Registration No. 2-26459
				June 1, 1966	Exhibit 2-M	to Registration No. 2-26459
				June 1, 1967	Exhibit 2-N	to Registration No. 2-29693
				September 1, 1968	Exhibit 4-O	to Registration No. 2-31569
				June 1, 1969	Exhibit 4-C	to Registration No. 33-38580
				December 1, 1969	Exhibit 4-O	to Registration No. 2-35388
				June 1, 1970	Exhibit 4-R	to Registration No. 2-37363
				March 1, 1971	Exhibit 2-B-17	to Registration No. 2-40324
				January 1, 1972	Exhibit 2-B	to Registration No. 33-38580

171

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	PSNC Energy	Description
				July 1, 1974	Exhibit 2-A-19	to Registration No. 2-51291
				May 1, 1975	Exhibit 4-C	to Registration No. 33-38580
				July 1, 1975	Exhibit 2-B-21	to Registration No. 2-53908
				February 1, 1976	Exhibit 2-B-22	to Registration No. 2-55304
				December 1, 1976	Exhibit 2-B-23	to Registration No. 2-57936
				March 1, 1977	Exhibit 2-B-24	to Registration No. 2-58662
				May 1, 1977	Exhibit 4-C	to Registration No. 33-38580
				February 1, 1978	Exhibit 4-C	to Registration No. 33-38580
				June 1, 1978	Exhibit 2-A-3	to Registration No. 2-61653
				April 1, 1979	Exhibit 4-C	to Registration No. 33-38580
				June 1, 1979	Exhibit 2-A-3	to Registration No. 33-38580
				April 1, 1980	Exhibit 4-C	to Registration No. 33-38580
				June 1, 1980	Exhibit 4-C	to Registration No. 33-38580
				December 1, 1980	Exhibit 4-C	to Registration No. 33-38580
				April 1, 1981	Exhibit 4-D	to Registration No. 33-38580
				June 1, 1981	Exhibit 4-D	to Registration No. 33-49421
				March 1, 1982	Exhibit 4-D	to Registration No. 2-73321
				April 15, 1982	Exhibit 4-D	to Registration No. 33-49421
				May 1, 1982	Exhibit 4-D	to Registration No. 33-49421
				December 1, 1984	Exhibit 4-D	to Registration No. 33-49421
				December 1, 1985	Exhibit 4-D	to Registration No. 33-49421
				June 1, 1986	Exhibit 4-D	to Registration No. 33-49421
				February 1, 1987	Exhibit 4-D	to Registration No. 33-49421
				September 1, 1987	Exhibit 4-D	to Registration No. 33-49421
				January 1, 1989	Exhibit 4-D	to Registration No. 33-49421
				January 1, 1991	Exhibit 4-D	to Registration No. 33-49421
				July 15, 1991	Exhibit 4-D	to Registration No. 33-49421
				August 15, 1991	Exhibit 4-D	to Registration No. 33-49421
				April 1, 1993	Exhibit 4-E	to Registration No. 33-49421
				July 1, 1993	Exhibit 4-D	to Registration No. 33-49421
				May 1, 1999	Exhibit 4.04	to Registration No. 333-86387
4.06	X	X		Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)
4.07	X	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	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)
4.09	X		X	Indenture dated as of January 1, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206 and incorporated by reference herein)

172

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	PSNC Energy	Description
4.10	X		X	First through Fourth Supplement Indenture referred to in Exhibit 4.09 dated as of the dates indicated below and filed as exhibits to the Registration Statements whose file number are set forth below and are incorporated by reference herein
				January 1, 1996          Exhibit 4.09       to Registration No. 333-45206 December 15, 1996     Exhibit 4.10       to Registration No. 333-45206 February 10, 2000       Exhibit 4.11       to Registration No. 333-45206 February 12, 2001       Exhibit 4.05       to Registration No. 333-68516
4.11			X	PSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516 and incorporated by reference herein)
4.12			X	Amended and Restated Five-Year Credit Agreement dated June 30, 2005 (Filed as Exhibit 4.12 to Form Q for the quarter ended June 30, 2005 and incorporated by reference herein)
*10.01	X	X	X	SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and incorporated by reference herein)
*10.02	X	X	X	SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by reference herein)
*10.03	X	X	X	Amendment to SCANA Director Compensation and Deferral Plan adopted April 29, 2004 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
*10.04	X	X	X	Amendment to SCANA Director Compensation Plan as adopted November 2, 2005 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2005 and incorporated by reference herein)
*10.05	X	X	X	SCANA Supplementary Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
*10.06	X	X	X	SCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
*10.07	X	X	X	SCANA Supplementary Key Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
*10.08	X	X	X	SCANA Long-Term Equity Compensation Plan dated January 2000 (Filed as Exhibit 4.04 to Registration Statement No. 333-37398 and incorporated by reference herein)
*10.09	X	X	X	Amendment to SCANA Long-Term Equity Compensation Plan adopted April 28, 2004 (Filed as Exhibit 10.08 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
*10.10	X	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)

173

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	PSNC Energy		Description
*10.11	X	X		X	SCANA Corporation Short-Term Annual Incentive Plan as amended and restated effective January 1, 2005 (Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2005 and incorporated by reference herein)
*10.12	X	X		X	Description of Amendment to SCANA Corporation Executive Annual Incentive Plan (Filed on Form 8-K dated February 23, 2005 and incorporated by reference herein)
10.13				X	Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.14				X	Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.15				X	Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.16				X	Amended Construction, Operation and Maintenance Agreement by and between Cardinal Operating Company and Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.04 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.17				X	Service Agreement between PSNC and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 10.15 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
10.18		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
12.02		X			Statement Re Computation of Ratios
12.03				X	Statement Re Computation of Ratios
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)
23.02		X			Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm)
23.03				X	Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm)
24.01	X	X		X	Power of Attorney (Filed herewith)
31.01	X				Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

174

	Applicable to Form 10-K of
Exhibit No.	SCANA	SCE&G	PSNC Energy	Description
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)
31.05			X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.06			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)
32.05			X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.06			X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

*Management Contract or Compensatory Plan or Arrangement

175