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 |
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For the Fiscal Year Ended December 31, 2005 2006 |
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OR |
| |
o¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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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 | 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 theThe 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 areregistrant is a large accelerated filers,filer, accelerated filers,filer, or non-accelerated filersfiler (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 ¨ Nox
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$4.5 billion at June 30, 2005,2006 based on the closing price of $42.71$38.58 per share. Each of the other registrantsSouth Carolina Electric & Gas Company is a wholly owned subsidiary of SCANA Corporation and has no voting stock other than its common stock. A description of registrants' common stock follows:
Registrant | Description of Common Stock | Shares Outstanding at February 20, 20062007 |
| SCANA Corporation | Without Par Value | 115,032,759116,664,933 |
| 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)40,296,147(a) |
(a) | Held beneficially and of record by SCANA Corporation. |
(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 20062007 Annual Meeting of Shareholders, are incorporated by reference in Part III hereof.
This combined Form 10-K is separately filed by SCANA Corporation and South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated.Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.company.
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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| 4 |
PART I | |
Item 1. | | |
| | 1514 |
Item 1B. | | 1917 |
Item 2. | | 2018 |
Item 3. | | 2220 |
Item 4. | | 2522 |
| 2623 |
PART II | |
Item 5. | | 2724 |
Item 6. | | 2925 |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
| Quantitative and Qualitative Disclosures About Market Risk | |
| Financial Statements and Supplementary Data | |
| | | 3026 |
| | | 94 |
| | 14081 |
| | 162127 |
9A. | | 162127 |
| | 165129 |
PART III | |
| Registrant | 166130 |
| | 169134 |
| | 175160 |
| | 176161 |
| | 177161 |
| |
| | 178162 |
| 180164 |
| 182166 |
The following abbreviations used in the text have the meanings set forth below unless the context requires otherwise:
TERM | MEANING |
| AFC | Allowance for Funds Used During Construction |
| CAA | Clean Air Act, as amended |
| CGTC | Carolina Gas Transmission Corporation |
| DHEC | South Carolina Department of Health and Environmental Control |
| DOE | United States Department of Energy |
| DOJ | United States Department of Justice |
| Dominion | Dominion Transmission, Inc. |
| DT | Dekatherm (one million BTUs) |
| Energy Marketing | The divisions of SEMI, excluding SCANA Energy |
| EPA | United States Environmental Protection Agency |
| FERC | United States Federal Energy Regulatory Commission |
| Fuel Company | South Carolina Fuel Company, Inc. |
| GENCO | South Carolina Generating Company, Inc. |
| GPSC | Georgia Public Service Commission |
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.A.M. Williams Generating Station, owned by GENCO |
| WNA | Weather Normalization Adjustment |
PART I
CORPORATE STRUCTURE
SCANA CORPORATIONCorporation (SCANA), a holding company, owns the following significant direct, wholly-owned subsidiaries.
SOUTH CAROLINA ELECTRICSouth Carolina Electric & GAS COMPANYGas Company (SCE&G) generates and sells electricity to retail and wholesale customers and purchases, sells and transports natural gas to retail customers.
SOUTH CAROLINA GENERATING COMPANY, INC.South Carolina Generating Company, Inc. (GENCO) owns and operates Williams Station and sells electricity solely to SCE&G.
SOUTH CAROLINA FUEL COMPANY, INC.South Carolina Fuel Company, Inc. (Fuel Company) acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowances.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATEDPublic Service Company of North Carolina, Incorporated (PSNC Energy), 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.Carolina Gas Transmission Corporation (CGTC) transports natural gas in southeastern Georgia and South Carolina. CGTC was formerly known as South Carolina Pipeline Corporation (SCPC), which merged with SCG Pipeline, Inc. (SCG Pipeline) effective November 1, 2006.
SCANA COMMUNICATIONS, INC.Communications, Inc. (SCI) provides fiber optic telecommunications,communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia.
SCANA ENERGY MARKETING, INC.Energy Marketing, Inc. (SEMI) markets natural gas, primarily in the Southeast, and provides energy-related risk management services. Through its SCANA Energy division, SEMI markets natural gas in Georgia's retail natural gas market.
SERVICECARE, INC.ServiceCare, Inc. provides service contracts on home appliances and heating and air conditioning units.
PRIMESOUTH, INC.Primesouth, Inc. provides management and maintenance services for power plants and a non-affiliated synthetic fuel production facility.
SCANA SERVICES, INC.Services, Inc. provides administrative, management and other services to the subsidiaries and business units within SCANA.
SCANA andis incorporated in South Carolina as is each of its direct, wholly-owned subsidiaries are incorporated under the laws of the State of South Carolina.subsidiaries. In addition to the subsidiaries above, SCANA owns two other energy-related companies that are insignificant and one additional company that is in liquidation.
4CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Statements included in this Annual Report on Form 10-K which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include, but are not limited to, statements concerning key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, estimated construction and other expenditures and factors affecting the availability of synthetic fuel tax credits. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:
(1) the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment;
(2) regulatory actions, particularly changes in rate regulation and environmental regulations;
(3) current and future litigation;
(4) changes in the economy, especially in areas served by subsidiaries of SCANA;
(5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial
interruptible markets;
(6) growth opportunities for SCANA's regulated and diversified subsidiaries;
(7) the results of financing efforts;
(8) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;
(9) weather conditions, especially in areas served by SCANA's subsidiaries;
(10) payment by counterparties as and when due;
(11) the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability
of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels
and purchased power; and the ability to recover the costs for such fuels and purchased power;
(12) performance of the Company's pension plan assets;
(13) inflation;
(14) compliance with regulations; and
(15) the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or its subsidiaries
with the United States Securities and Exchange Commission (SEC), including those risks described in Item 1A, Risk
Factors.
SCANA and SCE&G disclaim any obligation to update any forward-looking statements.
ORGANIZATION
SCANA is a South Carolina corporation having general business powers, iscreated in 1984 as a holding company and was incorporated in 1984.company. SCANA holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G. SCANA and its subsidiaries had full-time, permanent employees as of February 20, 2007 and 2006 of 5,683 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.utility incorporated in 1924 as a South Carolina corporation. SCE&G had full-time, permanent employees as of February 20, 2007 and 2006 of 2,908 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 and 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 foundInformation 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 LLClimited liability company (LLC) which owns and operates a cogeneration facility in Charleston, South Carolina.
InformationFor information with respect to major segments of business, is contained insee 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, distributiongenerates, transports (transmission and saledistribution) and sells electricity to 623,400 customers and buys, sells and transports (retail) natural gas to 297,000 customers (each as of electricity and in the purchase, sale and transport at retail of natural gas.December 31, 2006). SCE&G's business is subject toexperiences seasonal fluctuations. Generally,fluctuations, with generally higher sales of electricity are higher during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas are higher induring the winter months due to heating requirements. SCE&G's electric service areaterritory extends into 2624 counties covering more thannearly 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 4635 counties in South Carolina and covers more than 22,00023,000 square miles. The total population ofMore than 3.0 million persons live in the counties representing the combined service area is more than 3.0 million.where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries 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.allowances.
PSNC Energy is a public utility engaged primarily in purchasing, sellingbuys, sells and transportingtransports natural gas to approximately 425,400441,500 residential, commercial and industrial customers (as of December 31, 2005)2006). PSNC Energy provides service to itsserves 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.
Effective November 1, 2006, SCG Pipeline merged into SCPC isand the merged company changed its name to CGTC. CGTC operates as an open access, transportation-only interstate pipeline company regulated by the Federal Energy Regulatory Commission (FERC). CGTC operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural Gas Company (Southern Natural) at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGTC also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transcontinental Gas Pipeline Corporation (Transco) in Cherokee and Spartanburg counties, South Carolina. CGTC’s customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SEMI (which markets natural gas to industrial and sale for resale customers, primarily in the Southeast), other natural gas utilities, municipalities and county gas authorities, and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles.
Prior to the November 1, 2006 merger, SCPC was an intrastate natural gas pipeline engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G) and industrial customers throughout most of South Carolina. SCPC 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 provideshad provided 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)2006) in Georgia's natural gas market. The GPSCGeorgia Public Service Commission (GPSC) has contracted with SCANA Energy to serve as regulated provider. Currently, over 70,000 of SCANA Energy’s customers are served under the state’s regulated provider contract. This groupuntil August 31, 2007. Currently, SCANA Energy serves over 90,000 customers (as of December 31, 2006) under this regulated provider contract, which 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 aboutover a 30 percent30% share of the approximately 1.5 million customers in Georgia's deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.
SCI owns and operates a 500-mile fiber optic telecommunications network and ethernet network and data center facilities in South Carolina and, through itsCarolina. Through a joint venture, with FRC, LLC,SCI has an interest in an additional 1,0641,742 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.
OtherThe preceding Corporate Structure section describes other significant businesses owned by SCANA are described in the preceding Corporate Structure section.SCANA.
COMPETITION
For a discussion of the impact of competition, see the Overview section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G, and the Competition section of Management's Narrative Analysis of Results of Operations for PSNC Energy.&G.
CAPITAL REQUIREMENTS
Cash requirements for SCANA’s regulated subsidiaries arise primarily from their operational needs, funding theirrequire cash to fund operations, construction programs and payment of dividendsdividend payments to SCANA. The ability of the regulated subsidiaries toTo replace existing plant investment as well asand to expand to meet future demand for electricity and gas, will depend upon their ability toSCANA’s regulated subsidiaries must attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their 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, ifwhen requested.
For a discussion of the impact of various rate matters and their impact on capital requirements, see the Regulatory Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 2 to the consolidated financial statements for SCANA SCE&G and PSNC Energy.SCE&G.
During the three-year period 2006-2008,2007-2009, SCANA and 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 indebtednessborrowings. SCANA 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.
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&G.
SCANA's ratios of earnings to fixed charges were 2.94, 2.19, 2.65, 2.82 0.53 and 4.370.53 for the years ended December 31, 2006, 2005, 2004, 2003 2002 and 2001,2002, 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&G’s ratios of earnings to fixed charges were 3.08, 2.10, 3.15, 3.01 3.13 and 3.373.13 for the same periods. For PSNC Energy theseSCANA’s and SCE&G’s 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 was2005 were negatively impacted by the impairment chargelarge amounts of accelerated depreciation discussed at Results of Operations - Income Taxes - Recognition of Synthetic Fuel Tax Credits in their respective Management’s Discussion and Analysis of Financial Condition and Results of Operations sections, and because the calculation necessarily excludes the related to the acquisition adjustment described above.and fully offsetting tax benefits recorded in that year.
ELECTRIC OPERATIONS
Electric Sales
SCE&G's sales of electricity by class as a percent of total electric revenues for 2005 and 20042006 were as follows:
CLASSIFICATION | | 2004 | | 2005 | | | 2005 | | 2006 | |
| Residential | | | 40 | % | | 39 | % | | | 39 | % | | 40 | % |
| Commercial | | | 30 | % | | 29 | % | | | 29 | % | | 31 | % |
| Industrial | | | 17 | % | | 17 | % | | | 17 | % | | 17 | % |
| Sales for resale | | | 4 | % | | 4 | % | | | 4 | % | | 4 | % |
| Other | | | 2 | % | | 2 | % | | | 2 | % | | 2 | % |
| Total Territorial | | | 93 | % | | 91 | % | | | 91 | % | | 94 | % |
| NMST | | | 7 | % | | 9 | % | |
| Negotiated Market Sales Tariff (NMST) | | | | 9 | % | | 6 | % |
| Total | | | 100 | % | | 100 | % | | | 100 | % | | 100 | % |
Sales for resale include sales to four municipalities and one electric cooperative.five municipalities. Sales under the NMST during 2006 include sales to 25 investor-owned utilities or registered marketers, three electric cooperatives and three federal/state electric agencies. During 2005 includesales under the NMST included 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 20052006 SCE&G recorded a net increase of approximately 18,50013,400 customers (growth rate of 2.2%), increasing its total electric customers to approximately 610,000623,400 at year end. A new all-timeDuring 2006, SCE&G’s peak summer demand did not exceed the all-time peak demand of 4,820 MW wasmegawatts (MW) 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 2006-2008,2007-2009, SCE&G's&G projects total territorial KWhkilowatt hour (KWh) sales of electricity are projected to increase 2.4%2.2% annually assuming(assuming normal weather. SCE&G'sweather), total electric customer base is projected to increase 2.2% annually. Over the same three-year period, SCE&G's2.3% annually and territorial peak load (summer, in MW) is projected to increase 2.5%1.9% annually. SCE&G's goal is to maintain a reserve margin of between 12% and 18%. As of December 31, 20052006 the reserve margin was approximately 17%12.6%.
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'sStation has a net generating capacity.capacity (summer rating) of 615 MW.
SCE&G's transmission system isforms part of thean interconnected grid extending over a large part of the southern and eastern portions of the nation. SCE&G, Dominion Virginia Electric and Power, Company, Duke Power Company, Carolina Power & Light Company (ProgressCarolinas, Progress Energy Carolinas),Carolinas, APGI (Yadkin Division) and Santee Cooperthe South Carolina Public Service Authority (Santee Cooper) are members of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the Southeastern Electric Reliability Council. This Council provides(SERC). SERC is the Regional Reliability Organization (RRO) responsible for coordinated planning forpromoting, coordinating and ensuring the reliability amongand adequacy of the bulk power supply systems in the Southeast.area served by the member systems. SCE&G is also interconnectedinterconnects 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.
Fuel Costs and Fuel Supply
The following table sets forth the average cost of nuclear fuel, coal and gasvarious fuels and the weighted average cost of all fuels (including oil) for the years 2003-2005.2004-2006 follow:
| | | 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 | |
| | | Cost of Fuel Used | |
| | | 2004 | | 2005 | | 2006 | |
| Per million British thermal units (MMBTU): | | | | | | | |
| Nuclear | | $ | .50 | | $ | .46 | | $ | .43 | |
| Coal | | | 1.96 | | | 2.38 | | | 2.54 | |
| Gas | | | 7.54 | | | 10.50 | | | 8.18 | |
| All Fuels (weighted average) | | | 1.96 | | | 2.53 | | | 2.57 | |
| Per Ton: | | | | | | | | | | |
| Coal | | $ | 48.54 | | $ | 59.07 | | $ | 63.13 | |
| Per thousand cubic feet (MCF): | | | | | | | | | | |
| Gas | | $ | 7.81 | | $ | 10.91 | | $ | 8.57 | |
The following table shows the sources and approximate percentages of total MWhmegawatt hour (MWh) generation by each category of fuel for the years 2003-20052004-2006 and the estimates for the years 2006-2008.2007-2009 follow:
| | | % of Total MWh Generated | | | % of Total MWh Generated | |
| | | Actual | | Estimated | | | Actual | | Estimated | |
| | | 2003 | | 2004 | | 2005 | | 2006 | | 2007 | | 2008 | | | 2004 | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | |
| Coal | | | 70 | % | | 68 | % | | 68 | % | | 69 | % | | 66 | % | | 63 | % | | | 68 | % | | 68 | % | | 67 | % | | 61 | % | | 63 | % | | 62 | % |
| Nuclear | | | 21 | % | | 21 | % | | 19 | % | | 19 | % | | 20 | % | | 18 | % | | | 21 | % | | 19 | % | | 19 | % | | 19 | % | | 18 | % | | 18 | % |
| Hydro | | | 6 | % | | 4 | % | | 5 | % | | 5 | % | | 5 | % | | 5 | % | | | 4 | % | | 5 | % | | 4 | % | | 6 | % | | 5 | % | | 5 | % |
| Natural Gas & Oil | | | 3 | % | | 7 | % | | 8 | % | | 7 | % | | 9 | % | | 14 | % | | | 7 | % | | 8 | % | | 10 | % | | 14 | % | | 14 | % | | 15 | % |
| Total | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Coal is used at fiveSix of SCE&G'sthe fossil fuel-fired plants and GENCO's Williams Station.use coal. Unit train deliveries are used at all of these plantstrains and in some cases truck deliveries are used.trucks deliver coal to these plants.. On December 31, 20052006 SCE&G had approximately a 46-day63-day supply of coal in inventory and GENCO had approximately a 27-day supply.inventory.
Coal is obtained through long-term 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 11purchases. Long-term contracts exist with eight suppliers located in eastern Kentucky, Tennessee, West Virginia and southwest Virginia. Contract commitments, which expire at various times through 2009, areThese contracts provide for approximately 6.54.5 million tons annually, which is 94%71% of total expected coal purchases for 2006.2007. Sulfur restrictions on the contract coal range from 1.0% to 1.5%. These contracts expire at various times through 2010. Spot market purchases are expected to continue when needed or when prices are favorable.
SCANA and SCE&G believe that SCE&G's 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 the V. C. Summer Nuclear Station (Summer Station) through 2008.2009. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies:
Commitment | Contractor | Remaining RegionsRegions(a)(a) | Expiration Date |
EnrichmentUranium | United States Enrichment Corporation(b) | 19-2020-21 | 20082009 |
| Enrichment | United States Enrichment Corporation | 20-24 | 2014 |
| Fabrication | Westinghouse Electric Corporation | 19-2220-22 | 2011 |
(a)A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region 1819 was
loaded in 2005.2006.
SCE&G has on-sitecan store spent nuclear fuel storage capabilityon-site 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 isSummer Station has 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 DOEUnited States Department of Energy (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.
GAS OPERATIONS
Gas Sales-Regulated
Sales of natural gas by class as a percent of total regulated gas revenues sold or transported for 2005 and 20042006 were as follows:
| | | SCANA | | SCE&G | | PSNC Energy | | | SCANA | | SCE&G | |
CLASSIFICATION | | 2004 | | 2005 | | 2004 | | 2005 | | 2004 | | 2005 | | | 2005 | | 2006 | | 2005 | | 2006 | |
| Residential | | | 40.8 | % | | 40.6 | % | | 38.8 | % | | 36.6 | % | | 59.3 | % | | 58.3 | % | | | 40.6 | % | | 42.6 | % | | 36.6 | % | | 38.4 | % |
| Commercial | | | 24.7 | % | | 25.5 | % | | 32.3 | % | | 32.3 | % | | 28.9 | % | | 29.4 | % | | | 25.5 | % | | 25.6 | % | | 32.3 | % | | 30.2 | % |
| Industrial | | | 29.3 | % | | 29.6 | % | | 28.1 | % | | 30.6 | % | | 6.5 | % | | 8.1 | % | | | 29.6 | % | | 27.6 | % | | 30.6 | % | | 30.7 | % |
| Sales for Resale | | | 1.5 | % | | 1.3 | % | | - | | - | | - | | - | | | | 1.3 | % | | 0.9 | % | | - | | | - | |
| Transportation Gas | | | 3.7 | % | | 3.0 | % | | 0.8 | % | | 0.5 | % | | 5.3 | % | | 4.2 | % | | | 3.0 | % | | 3.3 | % | | 0.5 | % | | 0.7 | % |
| Total | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
For the three-year period 2006-2008, SCANA's2007-2009, SCANA projects total consolidated sales of regulated natural gas in DTs are projecteddekatherms (DT) to increase 1.4%2.2% annually assuming(assuming normal weather. Residentialweather). Annual projected increases in DT sales are projected to increaseinclude residential of 2.6%, commercial of 1.7% annually, commercial sales 1.4% and industrial sales 1.3%2.0%. Sales for resale are not expected to increase significantly.
SCANA's total consolidated natural gas customer base is projected to increase 2.0%3.6% annually.
During 20052006 SCANA recorded a net increase of approximately 23,50021,600 regulated gas customers (growth rate of 3.0%), increasing its regulated gas customers to approximately 717,000.739,000. Of this increase, SCE&G recorded a net increase of approximately 7,3005,500 gas customers (growth rate of 1.9%), increasing its total gas customers to approximately 292,000. PSNC Energy recorded a net increase297,000 (as of approximately 16,300 customers, increasing its total customers to approximately 425,000.December 31, 2006).
The demandDemand for gas is affected principally bychanges primarily due to the effect of weather and the price relationship between gas and alternate fuels.
For most of 2006, SCPC operatingoperated wholly within South Carolina providesand provided natural gas utility and transportation services for its industrial customers, and suppliessupplied natural gas to SCE&G and other wholesale purchasers. On November 1, 2006, SCG Pipeline was merged into SCPC, forming CGTC. CGTC is an interstate transmission pipeline regulated by FERC and 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.Georgia. See Gas Transmission within 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
SCG Pipeline merged into SCPC and the merged company changed its name to CGTC, effective November 1, 2006. As a result of this merger SCPC's existing customers were allocated their pro rata share of SCPC's upstream firm interstate pipeline transportation and storage contracts. In addition, SCPC transferred both of its LNG facilities to SCE&G. SCE&G purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. The gas is brought to South Carolina through transportation agreements with Southern Natural Gas Company (Southern Natural) (expiring in 2010) and Transco, Transcontinental Gas Pipeline Corporation (Transco) (expiring in 2008 and 2017) and CGTC (expiring 2009). The daily volume of gas that SCPCSCE&G is entitled to transport under these contracts on a firm basis is 188 MMCF161,143 DT from Southern Natural, and 93 MMCF from Transco. Of these daily amounts, 3.5 MMCF from Southern Natural and 1.9 MMCF64,652 DT from Transco have been temporarily released to the City of Orangeburg, and 22.3 MMCF296,560 DT from SouthernCGTC. 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 aremay be brought to SCPC'sSCE&G'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 either electric generation. SCG transports the gasgeneration or for resale to SCE&G&G’s customers.
The daily volume of gas that SEMI is entitled to transport under its service agreement with CGTC (expiring in 2023) on a separate contract.firm basis is 198,083 DT.
During 2005 SCPC'sSCE&G purchased natural gas at an average cost of $9.82 per MCF during 2006 and $10.29 per MCF during 2005.
SCE&G was allocated 5,406 MMCF 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 $10.29storage space on Southern Natural 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 costTransco. Approximately 4,660 MMCF of gas calculation. The offset to the changewere in fair value of these derivatives is recorded as a regulatory asset or liability.
storage on December 31, 2006. To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCPCSCE&G supplements its supplies of natural gas with two LNG liquefaction and storage facilities.facilities which it acquired from SCPC. The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately 1,7401,633 MMCF (liquefied equivalent) of gas were in storage at December 31, 2005. Additionally,2006. In the fourth quarter of 2006, SCE&G purchased these LNG plants and related inventory from SCPC has contractedat net book value and SCPC also assigned its rights and obligations under the contracts 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.
The SCPSC has established allocation priorities applicable toSCE&G and SCE&G purchased 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.related inventory at book value.
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. TheTransco and Dominion Transmission, Inc. (Dominion) deliver 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 tomay transport daily volumes of gas under these contracts on a firm basis isof 259,894 DT from Transco and 30,331 DT from Dominion Transmission.Dominion. 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'sEnergy purchased natural gas at an average cost of $9.47 per DT of natural gas purchased for resale, including firm service demand charges, was $10.63during 2006 compared to $7.95$10.63 per DT during 2004.2005.
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 12,00012,700 MMCF. Approximately 9,70011,200 MMCF of gas were in storage at December 31, 2005.2006. In addition, PSNC Energy's own LNG facility is capable of storingcan store the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day. Approximately 590600 MMCF (liquefied equivalent) of gas were in storage at December 31, 2005.2006. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,1001,200 MMCF (liquefied equivalent) were in storage at December 31, 2005.2006.
SCANA and 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.services primarily in the Southeast. In addition, SCANA Energy, a division of SEMI, markets natural gas to over 475,000 customers (as of December 31, 2005)2006) in Georgia's natural gas market. SCANA Energy's total customer base represents over a 30 percent30% 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.
PoliciesRisk Management
SCANA and SCE&G established 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.them. The Board of Directors of each company has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and to oversee and review the risk management process and infrastructure. The Risk Management Committee, which is comprised of certain officers, including a Risk Management Officer and senior officers, apprises the Board of Directors of each company with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
REGULATION
SCANA, 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 stateState public service commissions or FERC regulate certain subsidiaries of SCANA as to the following matters.
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters. SCE&G is subject to the jurisdiction of FERC as to issuance of short-term borrowings and other matters.
GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting and other matters.
PSNC Energy is subject to the jurisdiction of the NCUCNorth Carolina Utilities Commission (NCUC) as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.
SCPC is subject to the jurisdiction of the SCPSC as to gas rates, service, accounting and other matters.
SCG PipelineCGTC is subject to the jurisdiction of FERC as to gastransportation 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.
PursuantSCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act,Act). SCE&G and GENCO must obtain FERC authority to issue short-term indebtedness. SCE&G and GENCO have applied to FERC for authorization tomay 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&Gless, and GENCO may rely on the financing authority formerly provided under the Public Utility Holding Company Actissue up to $100 million of 1935, which act was repealed effectivesuch short-term indebtedness. FERC’s approval expires February 8, 2006.7, 2008.
SCE&G holds licenses under the Federal Water Power Act or the Federal Power Act with respect to allfor each of its hydroelectric projects. The expiration dates of the licenses covering the projects areexpire 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,SCE&G expects to apply to FERC granted SCE&G a temporary five-year license extension (until 2010) for relicensing of 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 2007.2008.
At the termination of a license under the Federal Power Act, FERC may extend or issue a new license to the United Statesprevious licensee, FERC may issue a license to another applicant or the federal government may take over the project covered thereby, or FERC may extend the license or issue a license to another applicant.related project. If the federal government takes over a project or if FERC issues a license to another applicant, the originalfederal government or the new licensee, is entitledas the case may be, must pay the previous licensee an amount equal 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.damages.
For a discussion of legislative and regulatory initiatives being implemented that will affect SCE&G's transmission system, see Electric Operations within the Overview section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCE&G is subject to regulation by the NRCUnited States Nuclear Regulatory Commission (NRC) with respect to the ownership, operation and decommissioning of Summer Station. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency is responsible for the review,reviews, 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.
SCE&G's and PSNC Energy's gas rate schedules for their residential and small commercial and small industrial customers include a WNA.weather normalization adjustment (WNA). SCE&G's and PSNC Energy's WNA were approved by the SCPSC and NCUC, respectively, and are in effect for bills rendered during the period November 1 through April 30 of each year. In each case the WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues; however, it does reducerevenues, but reduces fluctuations in revenues and earnings caused by abnormal weather.
Fuel Cost Recovery Procedures
The SCPSC has established aSCPSC’s 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 tomay 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, asAs part of the annual review of fuel costs, the SCPSC approved SCE&G’s request to increase the cost of fuel component from 1.7642.256 cents per KWh to 2.2562.516 cents per KWh effective the first billing cycle in May 2005. 2006.
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 SCPSCSCPSC. Beginning in December 2006, SCE&G is authorized to adjust its cost of gas on a monthly, rather than annual, gas cost and gas purchase practice hearings.basis.
PSNC Energy operates under two rate provisions inIn addition to WNA, that servePSNC Energy’s Rider D rate mechanism serves to reduce fluctuations in PSNC Energy'sEnergy’s earnings. First, itsThe Rider D rate mechanism allows PSNC Energy to recover, in any manner authorized by the NCUC, margin losses on negotiated gas and transportation sales. The Rider D rate mechanism also allows PSNC Energy to recover from customers all prudently incurred gas costs. Effective December 1, 2005 PSNC Energy may also recoverrecovers 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 and 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.
The risk factors that follow relate in each case to SCANA Corporation and its subsidiaries (SCANA)(the Company), 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,the Company's and 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 and other forms of energy and other gas suppliers.energy. Increases in gas costs may also result in lower usage by customers unable to switch to alternate fuels.
The Company and SCE&G do not fully hedge against price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.
The Company and SCE&G attempt to manage commodity price exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be diminished. SCANA,Changing and complex laws and regulations to which the Company and SCE&G and PSNC Energy are subject to complex government rate regulation, which could adversely affect revenues or increase costs or curtail activities, thereby adversely impacting results of operations, cash flows and cash flows.financial condition.
SCANA,The Company and SCE&G must comply with extensive federal, state and PSNC Energylocal laws and regulations. Such regulation widely affects the operation of our business. The effects encompass, among many other aspects of our business, the licensing and siting of facilities, safety, reliability of our transmission system, security of key assets, information privacy, the issuance of securities, financial reporting, interaction among affiliates, and the payment of dividends. Changes to these regulations are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or SCE&G’s business.
The Company and SCE&G are subject to extensive rate regulation which could adversely affect operations. In particular, SCE&G's electric operations in South Carolina and SCANA'sthe Company'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.
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 SCANAThe Company and SCE&G are vulnerable to compete ininterest rate increases which would increase our electric markets, therebyborrowing costs, and may not have access to capital at favorable rates, if at all, both of which may adversely impactingaffect results of operations, cash flows and financial condition.
Changes in interest rates can affect the cost of borrowing on variable rate debt outstanding, on refinancing of debt maturities and on incremental borrowing to fund new investments. The Energy Policy Act of 2005 (the “Energy Policy Act”) became law in August 2005.Company's and SCE&G’s business plans reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining investment grade debt ratings. The 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 provisionsliquidity of the Energy Policy Act. The Company is reviewing these rules and will monitor their implementation to determineSCE&G would be adversely affected by unfavorable changes in the impact they will have on SCE&G's access tocommercial paper market 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.if bank credit facilities became unavailable at acceptable rates.
Problems with operationsSCANA may not be able to maintain its leverage ratio at a level considered appropriate by debt rating agencies. This could cause us to incur substantialresult in downgrades of SCANA's debt ratings, thereby increasing its borrowing costs therebyand adversely impactingaffecting its results of operations, cash flows and financial condition.
SCANA's leverage ratio of debt to capital increased significantly following its acquisition in 2000 of PSNC Energy, and was approximately 55% at December 31, 2006. SCANA has publicly announced its desire to maintain this leverage ratio at 54% to 55%, but SCANA's ability to do so depends on a number of factors. If SCANA is not able to maintain its leverage ratio, SCANA's debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.
AsA downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect their ability to access capital and to operate their businesses, thereby adversely affecting results of operations, cash flows and financial condition.
Standard & Poor's Ratings Services (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) rate SCANA's long-term senior unsecured debt at BBB+, A3 and A-, respectively, each with a stable outlook. 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. S&P, Moody’s and Fitch rate PSNC Energy's long-term senior unsecured debt at A-, A2 and A, respectively, with a stable outlook. If S&P, Moody's or Fitch were to downgrade any of these long-term ratings, particularly to below investment grade, borrowing costs would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease. S&P, Moody's and Fitch rate the short-term debt of SCE&G and PSNC Energy at A-2, P-1 and F-1, respectively. If these short-term ratings were to decline, it could significantly limit access to the commercial paper market and other sources of liquidity.
Operating results may be adversely affected by abnormal weather.
The Company and SCE&G have historically sold less power, delivered less gas and received lower prices for natural gas in deregulated markets, and consequently earned less income, when weather conditions are milder than normal. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and SCE&G. In addition, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.
Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.
The utility industry has been undergoing dramatic structural change for several years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales has been introduced on a national level. Some states have also mandated or encouraged competition at the retail level. Increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, SCANA's and SCE&G's generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets would be required.
The Company and SCE&G are subject to risks associated with changes in business climate which could increase and adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.
Sales and sales growth is dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Some economic sectors important to our customer base may be particularly affected. Adverse events, economic or otherwise, may also affect the operations of key customers. The success of local and state governments in attracting new industry to our service territories is important to our growth in sales.
Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed.
Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.
Critical processes or systems in the Company’s or SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission line failure, information systems failure, and the effects of a pandemic or terrorist attack on our workforce or on the ability of vendors and suppliers to maintain services key to our operations.
In particular, as the operator of power generation facilities, SCE&G could incur problems such as the breakdown or failure of power generation 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.
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 2005.2006. 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 procurement of enriched uranium fuel;
· | Uncertainties with respect to contingencies if insurance coverage is inadequate; and
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives. |
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident, if a major incident should occur at a domestic nuclear facility, it could harm our results of operations, cash flows and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Finally, in today's environment, there is a heightened risk of terrorist attack on the nation's nuclear facilities, which has resulted in increased security costs at our nuclear plant.
ITEM 1B. UNRESOLVED STAFF COMMENTSFailure to retain and attract key personnel could adversely affect the Company’s and SCE&G’s operations and financial performance.
Not ApplicableImplementation of our strategic plan and growth strategy requires that we attract, retain and develop executive officers and other professional and technical employees with the skills and experience necessary to successfully manage our operations and grow our business. Competition for these employees is high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed.
The Company and SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial position, and access to capital.
From time to time, the Company and SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plant and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. In addition, these strategic decisions, which could be adverse to the Company’s or SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial position, as well as limit our ability to access capital.
None
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. ItSCANA also has an investment in one LLC which operates a cogeneration facility in Charleston, South Carolina.
SCE&G's bond indentures,indenture, securing the First and Refunding Mortgage Bonds and First Mortgage Bonds issued thereunder, constituteconstitutes a direct mortgage lienslien on substantially all of its electric utility 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 in South Carolina and North Carolina, though not depicted on the map, are also described below.
ELECTRIC PROPERTIES
Information onSCE&G owns each of the electric generating facilities all of which are owned by SCE&G except as noted, is as follows:listed below unless otherwise noted.
Facility | Present Fuel Capability | Location | Year In-Service | Net Generating Capacity (Summer Rating) (MW) |
| Steam Turbines | | | | |
| Summer(1) | Nuclear | Parr, SC | 1984 | 644 |
| McMeekin | Coal/Gas | Irmo, SC | 1958 | 250 |
| Canadys | Coal/Gas | Canadys, SC | 1962 | 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 (3)SCE&G receives shaft horse power from Cogen South, LLC to operate SCE&G's generator. Cogen South, LLC isowned 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. |
(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 440444 substations having an aggregate transformer capacity of 25.826.3 million KVA (kilovolt-ampere). The transmission system consists of 3,2193,218 miles of lines, and the distribution system consists of 17,77717,903 pole miles of overhead lines and 5,2175,608 trench miles of underground lines.
NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES
SCE&G's&G’s natural gas system consists of approximately 14,35015,144 miles of distribution mains and related service facilities. In 2006, 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 ownspurchased two LNG plants from SCPC, 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.
CGTC’s natural gas system consists of approximately1,472 miles of transmission pipeline of up to 24 inches in diameter, which connect its transportation customers’ distribution systems with the transmission systems of Southern Natural and Transco. CGTC’s system also includes 18 miles of transmission pipeline of up to 20 inches in 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'sEnergy’s natural gas system consists of approximately 880902 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 8,4808,880 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC Energy owns, through a wholly owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.
Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2005,2006, are described below. These issues affect SCANA and, to the extent indicated, also affect SCE&G or PSNC Energy.&G.
Environmental Matters
SCE&G owns a decommissioned MGPmanufactured gas plant (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,in late 2007, with certain monitoring and other activities continuing until 2011. As of December 31, 2005,2006, SCE&G has spent approximately $21.5$22.3 million to remediate the Calhoun Park site, and expects to spend an additional $0.3 million.$1.1 million prior to entering a monitoring and reporting stage. 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. AnySCE&G expects to recover any cost arising from the remediation of this matter is expected to be recoverablesite 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 South Carolina Department of Health and Environmental Control (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.by 2011. As of December 31, 2005,2006, SCE&G hashad spent approximately $4.5$4.8 million related to these three sites, and expects to spend an additional $11.5$11.2 million. AnySCE&G expects to recover any cost arising from this matter is expected to be recoverablethe remediation of these sites through rates.
SCE&G has been named, along with 2729 others, by the United States Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.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 and sale of used 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 dodoes not believe that SCE&G’sits involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this mattersite, net of insurance recoveries, if any, is expected to be recoverable through rates.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.
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$6.9 million, which reflects theits 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.2006. SCANA and PSNC Energy believe that all MGP cleanup costs incurred willany cost allocated to PSNC Energy arising from the remediation of these sites is expected to 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.
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 utilitiesutility’s internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may not go to trial in 2006.before 2008. 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 itstheir results of operations, cash flows or financial condition.
OnIn 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).Circuit. The plaintiff alleges SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA and SCE&G believe SCE&G’stheir actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted SCANASCANA’s and SCE&G’s motion to dismiss and issued an order dismissing the case onin June 29, 2005. The plaintiff has appealed.appealed to the South Carolina Supreme Court. The Supreme Court overruled the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration. It is anticipated that this case may not go to trial before 2008. SCANA and SCE&G intendwill continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on itstheir 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.claim against 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 believesSCANA and SCE&G believe that the resolution of these matters will not have a material adverse impact on itstheir results of operations, cash flows or financial condition.
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 isSettlement Related 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.Power Marketing Practices
On January 2, 2006,18, 2007, the Federal Energy Regulatory Commission (FERC) approved a settlement with SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgmentregarding the use of SCE&G’s discovery that it may have improperly utilizedelectric transmission system by its power marketing division. SCE&G identified, investigated and self-reported instances of improper utilization of 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 FERC 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 part of December 31, 2005,the settlement, SCE&G has recordedagreed that it would not retain any benefit derived from the transactions. SCE&G paid a loss accrual in the amount of approximately $0.8$9 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 modificationspenalty to the compliance plan or other non-monetary remedies. In additionU.S. Treasury. Additionally, SCE&G agreed to the disgorgement of profits, such remedies could also include penalties of upcredit an additional $1.4 million 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,benefit retail native load ratepayers and SCE&G’s institutionnon-affiliated firm transmission customers. The credit to the retail native load ratepayers was applied toward the fuel clause mechanism in January 2007. The credit to the non-affiliated firm transmission customers was refunded directly to those customers. An additional $0.4 million was credited to transmission revenue to the benefit 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&G’s retail rate payers. The effects of the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.settlement were accrued in 2006.
SCANA and 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.
The executive officers are elected at the annual meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such annual meeting, unless (1) a resignation is submitted, or unless(2) the Board of Directors shall otherwise determine.determine or (3) as provided in the By-laws of SCANA. Positions held are for SCANA and all subsidiaries unless otherwise indicated.
Name | Age | Positions Held During Past Five Years | Dates |
| | | | |
| William B. Timmerman | 5960 | Chairman of the Board, President and Chief Executive Officer | *-present |
| Jimmy E. Addison | 46 | Senior Vice President and Chief Financial Officer Vice President-Finance | 2006-present *-2006 |
| Joseph C. Bouknight | 5354 | Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA | 2004-present *-2004 |
| George J. Bullwinkel | 5758 | President and Chief Operating Officer-SEMI President and Chief Operating Officer-ServiceCare PresidentOfficer-SCI and Chief Operating Officer-SCIServiceCare
President and Chief Operating Officer-SCPC and SCG Pipeline Senior Vice President-Governmental Affairs and Economic Development
| 2004-present 2002-present
*-present 2002-2004
*-2002-2004 |
| Sarena D. Burch | 4849 | Senior Vice President-Fuel Procurement and Asset Management-SCE&G and PSNC Energy Senior Vice President-Fuel Procurement and SCPCAsset Management-SCPC Deputy General Counsel and Assistant Secretary-SCANA ServicesSecretary | 2003-present 2003-2006 *-2003 |
| Stephen A. Byrne | 4647 | Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G Senior Vice President-Nuclear Operations | 2004-present *-2004 |
PaulP. V. Fant | 5253 | Senior Vice President-SCANAPresident-Transmission Services Senior Vice President Transmission Services - SCE&G
President and Chief Operating Officer-SCPCOfficer-CGTC (formerly SCPC and SCG PipelineSCG) Executive Vice President-SCPC Executive Vice President-SCG and SCG Pipeline
| 2004-present 2004-present 2004-present
*-2004 2002-2004
|
Sharon K. JenkinsKevin B. Marsh | 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 | 5551 | President and Chief Operating Officer-SCEOfficer - SCE&G | *-present |
Kevin B. Marsh | 50 | Senior Vice President and Chief Financial Officer President and Chief Operating Officer-PSNC Energy | 2006-present *-present-2006 *-2003 |
| Charles B. McFadden | 6162 | Senior Vice President-Governmental Affairs and Economic Development-SCANADevelopment- SCANA Services Vice President-Governmental Affairs and Economic Development-SCANA Services | 2003-present *-2003 |
| Francis P. Mood, Jr. | 6869 | 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, 2001.2002.
PART II
ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,
COMMON STOCK INFORMATION
SCANA CorporationCorporation:
Price Range (New York Stock Exchange Composite Listing):
| | 2005 | | 2004 | 2006 | | 2005 |
| | 4th Qtr. | 3rd Qtr. | 2nd Qtr. | 1st Qtr. | | 4th Qtr. | 3rd Qtr. | 2nd Qtr. | 1st Qtr. | 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 | $42.43 | $41.65 | $40.41 | $41.42 | | $43.37 | $43.65 | $43.30 | $40.04 |
| Low | 37.79 | 39.90 | 36.56 | 36.70 | | 36.39 | 35.66 | 32.82 | 33.42 | $39.55 | $38.35 | $36.92 | $39.02 | | $37.79 | $39.90 | $36.56 | $36.70 |
The principal market for SCANA common stock is thetrades on The New York Stock Exchange, using the ticker symbol SCG. The corporateNewspaper stock listings use the name SCANA is used in newspaper stock listings.SCANA. At February 20, 20062007 SCANA common stock totaling 115,032,759116,664,933 shares were held by approximately 35,95734,326 stockholders of record. For a summary of equity securities issuable under SCANA's compensation plans at December 31, 2006, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
SCANA declared quarterly dividends on its common stock of $.42 per share in 2006 and $.39 per share and $.365 per share in 2005 and 2004, respectively.2005. On February 16, 2006,15, 2007, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.42$.44 per share, an increase of 7.7%4.8%. The new dividend is payable April 1, 20062007 to stockholders of record on March 10, 2006.9, 2007. 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.
SCE&G and PSNC Energy&G:
All of SCE&G's and PSNC Energy's common stock is owned by SCANA and has no market. During 20052006 and 20042005 SCE&G paid $150.5$151.5 million and $150.0$150.5 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)2007)
| | 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 FitchAll ratings carry a stable outlook. Moody's outlook is negative.
(2)All ratings carry a stable outlook.
AdditionalFor additional information regarding these securities, is provided insee 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.&G.
Securities ratings used by Moody's, Standard & Poors and Fitch are as follows:
Long-term (investment grade) | Short-term |
Moody's (3) (1) | S&P (4) (2) | Fitch (4) (2) | Moody's | S&P | Fitch |
| | | | | |
| Aaa | AAA | AAA | Prime-1 (P-1) | A-1 | F-1 |
| Aa | AA | AA | Prime-2 (P-2) | A-2 | F-2 |
| A | A | A | Prime-3 (P-3) | A-3 | F-3 |
| Baa | BBB | BBB | Not Prime | B | B |
| | | | | C | C |
| | | | | D | D |
(3)(1) Additional Modifiers: 1, 2, 3 (Aa to Baa)
(4) (2) Additional Modifiers: +/+, - (AA to BBB)
A security rating should be evaluated independently of other ratings and is not a recommendation to buy, sell or hold securities. In addition,The assigning rating organization may revise or withdraw its security ratings are subject to revision or withdrawal at any time by the assigning rating organization.time.
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.
ITEM 6.SELECTED FINANCIAL AND OTHER STATISTICAL DATA | | SCANA | SCE&G | | SCANA | | SCE&G | |
As of or for the Year Ended December 31, | 2005 | 2004 | 2003 | 2002 | 2001 | 2005 | 2004 | 2003 | 2002 | 2001 | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | |
| | (Millions of dollars, except statistics and per share amounts) | | (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 | | $ | 4,563 | | $ | 4,777 | | $ | 3,885 | | $ | 3,416 | | $ | 2,954 | | $ | 2,391 | | $ | 2,421 | | $ | 2,089 | | $ | 1,832 | | $ | 1,683 | |
| Operating Income | 436 | 596 | 551 | 514 | 528 | 312 | 475 | 440 | 431 | 439 | | | 603 | | 436 | | 596 | | 551 | | 514 | | 468 | | 312 | | 475 | | 440 | | 431 | |
| Other Income (Expense) | (162) | (219) | (138) | (397) | 309 | (121) | (111) | (101) | (90) | (86) | | | (164 | ) | | (162 | ) | | (219 | ) | | (138 | ) | | (397 | ) | | (121 | ) | | (121 | ) | | (111 | ) | | (101 | ) | | (90 | ) |
| Income Before Cumulative Effect of Accounting Change | 320 | 257 | 282 | 88 | 539 | 258 | 232 | 220 | 219 | 222 | | | 304 | | 320 | | 257 | | 282 | | 88 | | 230 | | 258 | | 232 | | 220 | | 219 | |
Net Income (Loss) (1) | 320 | 257 | 282 | (142) | 539 | 258 | 232 | 220 | 219 | 222 | | | 310 | | 320 | | 257 | | 282 | | (142 | ) | | 234 | | 258 | | 232 | | 220 | | 219 | |
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 | | | 115.8 | | 113.8 | | 111.6 | | 110.8 | | 106.0 | | 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 | | $ | 2.68 | | $ | 2.81 | | $ | 2.30 | | $ | 2.54 | | $ | (1.34 | ) | | 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 | | $ | 1.68 | | $ | 1.56 | | $ | 1.46 | | $ | 1.38 | | $ | 1.30 | | 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 | | $ | 7,007 | | $ | 6,734 | | $ | 6,762 | | $ | 6,417 | | $ | 5,474 | | $ | 5,748 | | $ | 5,580 | | $ | 5,621 | | $ | 5,293 | | $ | 4,729 | |
| Total Assets | 9,519 | 9,006 | 8,458 | 8,074 | 7,822 | 7,366 | 6,985 | 6,628 | 5,958 | 5,138 | | | 9,817 | | 9,519 | | 9,006 | | 8,458 | | 8,074 | | 7,626 | | 7,366 | | 6,985 | | 6,628 | | 5,958 | |
| Capitalization: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common equity | $2,677 | $2,451 | $2,306 | $2,177 | $2,194 | $2,362 | $2,164 | $2,043 | $1,966 | $1,750 | | $ | 2,846 | | $ | 2,677 | | $ | 2,451 | | $ | 2,306 | | $ | 2,177 | | $ | 2,457 | | $ | 2,362 | | $ | 2,164 | | $ | 2,043 | | $ | 1,966 | |
| Preferred Stock (Not subject to purchase or sinking funds) | 106 | 106 | 106 | 106 | 106 | 106 | 106 | | | 106 | | 106 | | 106 | | 106 | | 106 | | 106 | | 106 | | 106 | | 106 | | 106 | |
| Preferred Stock, net (Subject to purchase or sinking funds) | 8 | 9 | 9 | 10 | 8 | 9 | 10 | | | 8 | | 8 | | 9 | | 9 | | 9 | | 8 | | 8 | | 9 | | 9 | | 9 | |
| SCE&G—Obligated Mandatorily Redeemable | | | | | | | | |
SCE&G-Obligated Mandatorily Redeemable | | | | | | | | | | | | | | | | | | | | | | | |
| Preferred Securities of SCE&G Trust I | - | - | 50 | 50 | - | - | 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 | | | 3,067 | | | 2,948 | | | 3,186 | | | 3,225 | | | 2,834 | | | 2,008 | | | 1,856 | | | 1,981 | | | 2,010 | | | 1,604 | |
| Total Capitalization | $5,739 | $5,752 | $5,646 | $5,176 | $5,006 | $4,332 | $4,260 | $4,168 | $3,735 | $3,402 | | $ | 6,027 | | $ | 5,739 | | $ | 5,752 | | $ | 5,646 | | $ | 5,176 | | $ | 4,579 | | $ | 4,332 | | $ | 4,260 | | $ | 4,168 | | $ | 3,735 | |
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 | | | 623,402 | | 609,971 | | 585,264 | | 570,940 | | 560,224 | | 623,453 | | 610,025 | | 585,326 | | 570,994 | | 560,248 | |
| Total sales (Million KWh) | 25,140 | 25,031 | 22,516 | 23,085 | 22,928 | 25,158 | 25,050 | 22,531 | 23,085 | 22,928 | | | 24,523 | | 25,309 | | 25,031 | | 22,516 | | 23,085 | | 24,542 | | 25,327 | | 25,050 | | 22,531 | | 23,085 | |
| 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 | |
Generating capability-Net MW (Year-End) | | | | 5,749 | | 5,808 | | 5,817 | | 4,880 | | 4,866 | | 5,749 | | 5,808 | | 5,817 | | 4,880 | | 4,866 | |
| Territorial peak demand-Net MW | | | | 4,820 | | 4,820 | | 4,574 | | 4,474 | | 4,404 | | 4,820 | | 4,820 | | 4,574 | | 4,474 | | 4,404 | |
| 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 | | | 738,317 | | 716,794 | | 693,172 | | 672,849 | | 657,950 | | 297,165 | | 291,607 | | 284,355 | | 278,463 | | 274,334 | |
| 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 | | | 996,173 | | 1,106,526 | | 1,124,555 | | 1,205,730 | | 1,354,400 | | 403,489 | | 410,700 | | 399,601 | | 399,392 | | 398,991 | |
| Retail Gas Marketing: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Retail customers (Year-End) | 479,382 | 472,468 | 415,573 | 374,872 | 385,581 | n/a | n/a | n/a | | | 482,822 | | 479,382 | | 472,468 | | 415,573 | | 374,872 | | 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 | | | 335,896 | | 379,913 | | 379,712 | | 356,256 | | 337,858 | | 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 | |
Nonregulated interruptible customer deliveries (Thousand Therms) | | | | 1,239,926 | | 1,010,066 | | 917,875 | | 735,902 | | 852,608 | | n/a | | n/a | | n/a | | n/a | | n/a | |
| | | | 1,239,926 | | 1,010,066 | | 917,875 | | 735,902 | | 852,608 | | n/a | | n/a | | n/a | | n/a | | n/a | |
(1) Reflects write-downthe 2006 adoption of $230 million for goodwill impairment,Statement of Financial Accounting Standards (SFAS) 123(R), recorded as the cumulative effect of an accounting change
of $6 million for SCANA and $4 million for SCE&G, and the write-down in 2002 onof $230 million for SCANA for goodwill impairment, recorded as the
cumulative effect of an accounting change, upon adoption of SFAS 142.
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| | Environmental Matters | 40 |
| | Regulatory Matters | 42 |
| | Critical Accounting Policies and Estimates | 43 |
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| | | | 6353 |
| | | | 6454 |
| | | |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
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.
SCANA, through its wholly owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and distributionsale 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 offollowing map indicates areas where the Company’s significant business segments are conducted primarily in the areas indicated on the following map, andtheir activities, as further described in this overview section.
Following are
The following percentages of the Company’sreflect revenues and net income earned by the Company’s regulated and nonregulated businesses and the percentage of total assets held by them.
% of Revenues | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| Regulated | | | 69 | % | | 71 | % | | 73 | % | | | 69 | % | | 69 | % | | 71 | % |
| Nonregulated | | | 31 | % | | 29 | % | | 27 | % | | | 31 | % | | 31 | % | | 29 | % |
| | | | | | | | | | | | | | | | | | | | | |
% of Net Income (Loss) | | | 2005 | | | 2004(a | ) | | 2003 | | | | 2006(b | ) | | 2005 | | | 2004(a | ) |
| Regulated | | | 92 | % | | 106 | % | | 92 | % | | | 89 | % | | 92 | % | | 106 | % |
| Nonregulated | | | 8 | % | | (6 | )% | | 8 | % | | | 11 | % | | 8 | % | | (6 | )% |
| | | | | | | | | | | | | | | | | | | | | |
% of Assets | | | 2005 | | | 2004 | | | 2003 | | | | 2006 | | | 2005 | | | 2004 | |
| Regulated | | | 94 | % | | 94 | % | | 93 | % | | | 93 | % | | 94 | % | | 94 | % |
| Nonregulated | | | 6 | % | | 6 | % | | 7 | % | | | 7 | % | | 6 | % | | 6 | % |
(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. |
(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 ($29.8 million, net of tax) recognized on the sale of certain of the Company’s telecommunications investments and a charge ($11.1 million, net of taxes) related to pending litigation associated with the Company’s 1999 sale of its propane assets.
(b) In 2006, net income for non-regulated businesses included a reduction of the litigation accrual referred to above upon the settlement of that litigation. See Results of Operations for more information.
Key earnings drivers for the Company over the next five years will be additions to utility rate base at SCE&GSouth Carolina Electric & Gas Company (SCE&G) and PSNC Energy, drivenPublic Service Company of North Carolina, Incorporated (PSNC Energy), consisting primarily byof 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 limitingcontrolling the growth of operation and maintenance expenses.
Electric Operations
The electric operations segment is comprised of the electric operations of SCE&G, GENCOSouth Carolina Generating Company, Inc (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation, transmission, distribution and distributionsale of electricity in South Carolina. At December 31, 20052006 SCE&G provided electricity to approximately 610,000623,400 customers in an area covering approximatelynearly 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 amountis 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 monitormonitoring 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.
Gas Distribution
The gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy, and is primarily engaged in the purchase, transmission and sale of natural gas to retail customers in portions of North Carolina and South Carolina. At December 31, 20052006 this segment provided natural gas to approximately 717,000738,500 customers in an areaareas covering approximately 34,00035,000 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 beingwere not experienced in 2006 or in January or February of 2007, the price of natural gas remains volatile and has resulted in short-term competitive pressure. The long-term impact of volatile gas prices and gas supply has not been determined.
Gas Transmission
For 2005Effective November 1, 2006, SCG Pipeline merged into SCPC, and the merged company changed its name to Carolina Gas Transmission Corporation (CGTC). CGTC operates an open access, transportation-only interstate pipeline company regulated by FERC. CGTC’s operating results are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Demand for CGTC’s services is closely linked to demand for natural gas and is affected by the price of alternate fuels and customer growth. CGTC provides transportation services to SCE&G for its gas distribution customers and for certain electric generation needs and to SCANA Energy Marketing, Inc. (SEMI) for natural gas marketing. CGTC also provides transportation services to other natural gas utilities, municipalities and county gas authorities and to industrial customers.
Prior to the merger, the gas transmission segment was comprised solely of SCPC, which ownsowned and operatesoperated 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. OperatingSCPC’s 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)2006) throughout Georgia. SCANA Energy’s total customer base represents aboutover a 30 percent30% 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 Marketing 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,Georgia Public Service Commission (GPSC), and it receives funding from the Universal Service Fund for some of the bad debt associated with the low-income group. In June 2005, the Georgia Public Service Commission (GPSC) voted to retain SCANA EnergyEnergy’s service as Georgia’s regulated provider of natural gas ends August 31, 2007. In February 2007, the GPSC initiated a request for proposal (RFP) bidding process which may be used to select a regulated provider for a two-year period ending August 31, 2007, with an option bynew term. Notwithstanding that process, in which SCANA Energy is expected to participate, the GPSC may elect to extend theSCANA Energy’s current contract term for an additionalby one year. In connection with this contract extension, SCANA Energy has agreed to filefiles financial and other information periodically with the GPSC, and such information will beis available at www.psc.state.ga.us. At December 31, 2005,2006, SCANA Energy’s regulated division served over 70,00090,000 customers.
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.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.
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 | | | 2006 | | 2005 | | 2004 | |
| Reported (GAAP) earnings per share | | $ | 2.81 | | $ | 2.30 | | $ | 2.54 | | | $ | 2.68 | | $ | 2.81 | | $ | 2.30 | |
| Add (Deduct): | | | | | | | | | | | | | | | | | | | | |
| Cumulative effect of accounting change, net of tax | | | | (.05 | ) | | - | | | - | |
| Charge (reduction in charge) related to propane litigation | | | | (.04 | ) | �� | - | | | .10 | |
| Gains from sales of telecommunications investments | | | (.03 | ) | | - | | | (.35 | ) | | | - | | | (.03 | ) | | - | |
| Losses from sales of telecommunications investments | | | - | | | .14 | | | - | | | | - | | | - | | | .14 | |
| Telecommunications investment impairments | | | - | | | .13 | | | .31 | | | | - | | | - | | | .13 | |
| Charge related to pending litigation | | | - | | | .10 | | | - | | |
| GAAP-adjusted net earnings from operations per share | | $ | 2.78 | | $ | 2.67 | | $ | 2.50 | | | $ | 2.59 | | $ | 2.78 | | $ | 2.67 | |
| Cash dividends declared (per share) | | $ | 1.56 | | $ | 1.46 | | $ | 1.38 | | | $ | 1.68 | | $ | 1.56 | | $ | 1.46 | |
Discussion of above adjustments:
Realized gains (losses) on telecommunications investmentsThe cumulative effect of $.03, $(.14) and $.35 were recognizedan accounting change 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 20052006 resulted from the receipt in 2005Company’s adoption of additional proceeds from the 2003 saleStatement 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)Financial Accounting Standard (SFAS) 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)).
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 pendingpropane 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.The litigation was settled in 2006 for an amount that was less than had been previously accrued. See also Note 10 to the consolidated financial statements.
Realized gains in 2005 and realized losses in 2004 were recognized on sales of telecommunications investments. Unrealized impairments on certain of these investments were recognized in 2004. All significant telecommunications investments have now been monetized.
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 certain 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 (and reduction) 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 | | | 2006 | | 2005 | | 2004 | |
| | | | | |
| Income Statement Impact: | | | | | | | | | | | | | | | | | | | | |
| (Component of) reduction in employee benefit costs | | $ | 4.3 | | $ | 2.9 | | $ | (2.3 | ) | |
| Reduction in employee benefit costs | | | $ | 0.7 | | $ | 4.3 | | $ | 2.9 | |
| Other income | | | 11.9 | | | 10.8 | | | 7.9 | | | | 12.3 | | | 11.9 | | | 10.8 | |
| 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 | ) | |
| Reduction in capital expenditures | | | | 0.3 | | | 1.3 | | | 1.0 | |
| Component of amount due to Summer Station co-owner | | | | 0.2 | | | 0.6 | | | 0.4 | |
| Total Pension Income | | $ | 18.1 | | $ | 15.1 | | $ | 5.0 | | | $ | 13.5 | | $ | 18.1 | | $ | 15.1 | |
For the last several years, the market value of the Company’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income’s significant increase in 2004 is consistent with overall investment market results.Among the reasons 2006’s income was lower than 2005’s was a reduction of the assumed rate of return on plan assets from 9.25% to 9%. See also the discussion of pension accounting in Critical Accounting Policies and Estimates.
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 1.4%2.0% of income before income taxes in 2006, 1.4% in 2005 and 6.8% in 2004 and 7.4% in 2003.
2004. 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 Damback-up 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 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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Operating revenues | | $ | 1,908.3 | | 13.1 | % | $ | 1,687.7 | | 15.1 | % | $ | 1,466.5 | | | $ | 1,877.6 | | (1.6 | )% | $ | 1,908.3 | | | 13.1 | % | $ | 1,687.7 | |
| Less: Fuel used in generation | | | 618.3 | | 32.4 | % | | 466.9 | | 39.7 | % | | 334.1 | | | | 615.1 | | (0.5 | )% | | 618.3 | | | 32.4 | % | | 466.9 | |
| Purchased power | | | 37.2 | | | (26.6 | )% | | 50.7 | | | (20.8 | )% | | 64.0 | | | | 27.5 | | (26.1 | )% | | 37.2 | | | (26.6 | )% | | 50.7 | |
| Margin | | $ | 1,252.8 | | | 7.1 | % | $ | 1,170.1 | | | 9.5 | % | $ | 1,068.4 | | | $ | 1,235.0 | | | (1.4 | )% | $ | 1,252.8 | | | 7.1 | % | $ | 1,170.1 | |
| • | 2006 vs 2005 | Margin decreased by $20.8 million due to unfavorable weather, by $16.0 million due to decreased off-system sales and by $6.5 million due to lower industrial sales. These decreases were offset by residential and commercial customer growth of $26.5 million. Purchased power cost decreased due to lower volumes. |
| • | 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 cost 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. |
MWhMegawatt hour (MWh) sales volumes by class, related to the electric margin above, were as follows:
Classification (in thousands) | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Residential | | | 7,634 | | 2.3 | % | | 7,460 | | 6.6 | % | | 6,998 | | | | 7,598 | | (0.5 | )% | | 7,634 | | 2.3 | % | | 7,460 | |
| Commercial | | | 7,047 | | 2.1 | % | | 6,900 | | 4.4 | % | | 6,607 | | | | 7,249 | | 1.9 | % | | 7,117 | | 3.1 | % | | 6,900 | |
| Industrial | | | 6,651 | | (1.8 | )% | | 6,775 | | 3.5 | % | | 6,548 | | | | 6,183 | | (6.0 | )% | | 6,581 | | (2.9 | )% | | 6,775 | |
| Sales for resale (excluding interchange) | | | 1,487 | | (2.5 | )% | | 1,525 | | 6.1 | % | | 1,438 | | | | 1,487 | | - | | | 1,487 | | (2.5 | )% | | 1,525 | |
| Other | | | 527 | | | 0.2 | % | | 526 | | | 5.2 | % | | 500 | | | | 531 | | 0.8 | % | | 527 | | 0.2 | % | | 526 | |
| Total territorial | | | 23,346 | | 0.7 | % | | 23,186 | | 5.0 | % | | 22,091 | | | | 23,048 | | (1.3 | )% | | 23,346 | | 0.7 | % | | 23,186 | |
| NMST | | | 1,794 | | | (2.8 | )% | | 1,845 | | | * | | | 425 | | |
| Negotiated Market Sales Tariff (NMST) | | | | 1,475 | | (24.9 | )% | | 1,963 | | 6.4 | % | | 1,845 | |
| Total | | | 25,140 | | | 0.4 | % | | 25,031 | | | 11.2 | % | | 22,516 | | | | 24,523 | | | (3.1 | )% | | 25,309 | | | 1.1 | % | | 25,031 | |
* Greater than 100%
| • | 2006 vs 2005 | Territorial sales volumes decreased by 307 MWh due to lower industrial sales volumes and by 406 MWh due to unfavorable weather. These decreases were partially offset by 408 MWh due to residential and commercial customer growth. |
| • | 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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Operating revenues | | $ | 1,168.6 | | 27.9 | % | $ | 913.9 | | 5.2 | % | $ | 869.0 | | | $ | 1,078.0 | | | (7.8 | )% | $ | 1,168.6 | | 27.9 | % | $ | 913.9 | |
| Less: Gas purchased for resale | | | 894.6 | | | 36.6 | % | | 655.1 | | | 9.3 | % | | 599.3 | | | | 787.1 | | | (12.0 | )% | | 894.6 | | 36.6 | % | | 655.1 | |
| Margin | | $ | 274.0 | | | 5.9 | % | $ | 258.8 | | | (4.0 | )% | $ | 269.7 | | | $ | 290.9 | | | 6.2 | % | $ | 274.0 | | | 5.9 | % | $ | 258.8 | |
| • | 2006 vs 2005 | Margin increased by $17.5 million due to increased retail gas base rates which became effective with the first billing cycle in November 2005 and by $4.0 million due to an SCPSC-approved increase in retail gas base rates effective with the first billing cycle in November 2006. These increases were offset by $4.0 million due to lower firm margin resulting from customer conservation at SCE&G. The NCUC-approved rate increase at PSNC Energy, effective with the first billing cycle in November 2006, increased margin by $2.4 million, but was offset primarily by customer conservation. |
| • | 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. |
DTDekatherm (DT) sales volumes by class, including transportation gas, were as follows:
Classification (in thousands) | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Residential | | | 37,860 | | 1.7 | % | | 37,231 | | (3.4 | )% | | 38,542 | | | | 32,879 | | (13.2 | )% | | 37,860 | | 1.7 | % | | 37,231 | |
| Commercial | | | 27,750 | | 1.8 | % | | 27,271 | | (1.6 | )% | | 27,715 | | | | 25,718 | | (7.3 | )% | | 27,750 | | 1.8 | % | | 27,271 | |
| Industrial | | | 20,833 | | 7.8 | % | | 19,320 | | (3.9 | )% | | 20,109 | | | | 21,209 | | 1.8 | % | | 20,833 | | 7.8 | % | | 19,320 | |
| Transportation gas | | | 27,698 | | (1.8 | )% | | 28,216 | | 11.1 | % | | 25,387 | | | | 30,147 | | 8.8 | % | | 27,698 | | (1.8 | )% | | 28,216 | |
| Sales for resale | | | - | | | * | | | 1 | | | * | | | 1 | | | | - | | - | | | - | | (100.0 | )% | | 1 | |
| Total | | | 114,141 | | | 1.9 | % | | 112,039 | | | 0.3 | % | | 111,754 | | | | 109,953 | | | (3.7 | )% | | 114,141 | | | 1.9 | % | | 112,039 | |
* Not meaningful
| • | 2006 vs 2005 | Residential and commercial sales volumes decreased primarily due to milder weather and conservation. Transportation sales volumes increased primarily due to interruptible customers using gas instead of alternate fuels. |
| • | 2005 vs 2004 | Commercial and industrial sales 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. |
Gas Transmission
Gas Transmission is comprised of the operations of SCPC.CGTC and, for periods prior to the name change and merger, SCPC and SCG Pipeline for all periods presented. Gas transmission transportation revenues and sales margins (including transactions with affiliates) were as follows:
Millions of dollars | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Operating revenues | | $ | 658.0 | | 19.4 | % | $ | 550.9 | | 6.0 | % | $ | 519.8 | | |
| Transportation revenue | | | $ | 26.5 | | 40.2 | % | $ | 18.9 | | 6.2 | % | $ | 17.8 | |
| Other operating revenues | | | | 475.0 | | (26.5 | )% | | 646.3 | | 19.6 | % | | 540.2 | |
| Less: Gas purchased for resale | | | 604.2 | | | 21.6 | % | | 496.9 | | | 5.2 | % | | 472.2 | | | | 439.2 | | (27.3 | )% | | 604.2 | | 21.6 | % | | 496.9 | |
Margin | | $ | 53.8 | | | (0.4 | )% | $ | 54.0 | | | 13.4 | % | $ | 47.6 | | | $ | 62.3 | | | 2.1 | % | $ | 61.0 | | | (0.2 | )% | $ | 61.1 | |
| • | 2006 vs 2005 | Margin increased by $6.2 million due to increased transportation capacity charges (as a result of the merger discussed previously in the Overview section) and by $1.4 million due to higher interruptible transportation revenues, offset by $1.8 million due to decreased firm sales capacity charges and by $4.5 million due to lower industrial margins. |
| • | 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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Commercial | | | 54 | | (52.2 | )% | | 113 | | 5.6 | % | | 107 | | | | 23 | | | (57.4 | )% | | 54 | | (52.2 | )% | | 113 | |
| Industrial | | | 22,748 | | (20.5 | )% | | 28,625 | | (8.9 | )% | | 31,436 | | | | 18,875 | | | (17.0 | ) | | 22,748 | | (20.5 | )% | | 28,625 | |
| Transportation | | | 24,801 | | (1.8 | )% | | 25,252 | | * | | 12,262 | | | | 57,546 | | | 27.7 | | | 45,055 | | 18.3 | % | | 38,078 | |
| Sales for resale | | | 43,763 | | | 1.9 | % | | 42,946 | | | (9.4 | )% | | 47,391 | | | | 33,327 | | | (23.8 | ) | | 43,763 | | 1.9 | % | | 42,946 | |
| Total | | | 91,366 | | | (5.7 | )% | | 96,936 | | | 6.3 | % | | 91,196 | | | | 109,771 | | | (1.7 | ) | | 111,620 | | | 1.7 | % | | 109,762 | |
* Greater than 100%
| • | 2006 vs 2005 | Prior to the merger on November 1, 2006, industrial volumes decreased primarily due to higher commodity gas prices relative to alternate fuels. Subsequent to the merger, CGTC operates as a transportation-only interstate pipeline. |
| • | 2005 vs 2004 | Industrial volumes decreased primarily due to higher commodity gas prices relative to alternativealternate 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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Operating revenues | | $ | 663.8 | | 20.3 | % | $ | 552.0 | | 23.1 | % | $ | 448.3 | | | $ | 608.1 | | | (8.4 | )% | $ | 664.0 | | 20.3 | % | $ | 552.0 | |
| Net income | | | 24.1 | | | (16.9 | )% | | 29.0 | | | 44.3 | % | | 20.1 | | | | 30.1 | | | 24.9 | % | | 24.1 | | | (16.9 | )% | | 29.0 | |
| • | 2006 vs 2005 | Operating revenues decreased primarily due to milder weather and customer conservation, resulting in lower customer usage, which was partially offset by higher average retail prices arising from higher commodity gas costs. Net income increased primarily due to decreased bad debt of $9.0 million and lower operating and customer service expenses of $6.2 million, partially offset by a margin decrease of $9.1 million, net of taxes. |
| • | 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, 2004totaled 33.6 million DT in 2006 and 2003 totaled 37.9 million 37.9 millionDT in each of 2005 and 35.6 million DT, respectively.2004. Volumes declined in 2006 compared to 2005 and 2004 due to milder weather and customer conservation.
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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Operating revenues | | $ | 945.6 | | 58.5 | % | $ | 596.5 | | 43.5 | % | $ | 415.7 | | | $ | 948.7 | | | 0.3 | % | $ | 945.5 | | 58.5 | % | $ | 596.5 | |
| Net loss | | | (0.6 | ) | | 70.0 | % | | (2.0 | ) | | (81.8 | )% | | (1.1 | ) | | | (0.4 | ) | | (33.3) | % | | (0.6 | ) | | (70.0) | % | | (2.0 | ) |
| • | 2006 vs 2005 | Operating revenues increased due primarily to higher sales volume. Net loss decreased due to lower operating expenses of $1.0 million which was offset by lower margin on sales of $0.9 million. |
| • | 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 approximately123.9 million DT in 2006, 101.0 million DT in 2005 and 91.8 million DT in 2004. Delivered volumes increased in 2006 compared to 2005 primarily as a result of increased service to electric generation facilities and 73.6 million DT, respectively.municipalities in Georgia and South Carolina. 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 theSCE&G’s Jasper County Electric Generating Station in 2004, which created 11.2 million DT of additional volume.2004.
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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Other operation and maintenance | | $ | 632.0 | | 4.0 | % | $ | 607.5 | | 8.8 | % | $ | 558.3 | | | $ | 619.2 | | | (2.0 | )% | $ | 632.0 | | 4.0 | % | $ | 607.5 | |
| Depreciation and amortization | | | 509.9 | | 92.3 | % | | 265.1 | | 11.2 | % | | 238.3 | | | | 332.4 | | | (34.8 | )% | | 509.9 | | 92.3 | % | | 265.1 | |
| Other taxes | | | 145.0 | | | (0.4 | )% | | 145.6 | | | 4.6 | % | | 139.2 | | | | 151.8 | | | 4.7 | % | | 145.0 | | (0.4 | )% | | 145.6 | |
| Total | | $ | 1,286.9 | | | 26.4 | % | $ | 1,018.2 | | | 8.8 | % | $ | 935.8 | | | $ | 1,103.4 | | | (14.3 | )% | $ | 1,286.9 | | | 26.4 | % | $ | 1,018.2 | |
| • | 2006 vs 2005 | Other operation and maintenance expenses decreased by $13.9 million due to lower bad debts and by $9.5 million due to lower operating and customer service expenses, both at retail gas marketing, and by $22.5 million due to decreased incentive compensation expense. These decreases were partially offset by $11.1 million due to increased electric, generation, transmission and distribution expenses, by $3.1 million due to increased gas distribution expenses, by $3.6 million due to lower pension income and by $2.0 million due to higher customer service expenses at SCE&G. Depreciation and amortization expense decreased by $185.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2006 (see Income Taxes -Recognition of Synthetic Fuel Tax Credits), partially offset by $6.7 million due to property additions and higher depreciation rates at SCE&G. Other taxes increased primarily due to higher property taxes. |
| • | 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.million (at SCE&G). Depreciation and amortization increased approximately $214.0 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at (see Income Taxes -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 increased $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)
Other income (expense) includes the results of certain incidental (non-utility) activities and the activities of certain non-regulated subsidiaries. Components of other income (expense), excluding the equity component of AFC, were as follows:
Millions of dollars | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | | 2006 | | % Change | | | 2005 | | % Change | | | 2004 | |
| Gain (loss) on sale of investments | | $ | 7.2 | | * | | $ | (21.0 | ) | | * | | $ | 59.8 | | | $ | - | | | (100.0 | )% | $ | 7.2 | | * | | $ | (21.2 | ) |
| Gain on sale of assets | | | 1.7 | | * | | 0.7 | | (41.7 | )% | | 1.2 | | |
| Gains on sales of assets | | | | 3.4 | | | 100.0 | % | | 1.7 | | * | | | 0.7 | |
| Impairment of investments | | | - | | * | | (26.9 | ) | | (49.3 | )% | | (53.1 | ) | | | - | | | - | | | - | | (100.0 | )% | | (26.9 | ) |
| Other revenues | | | 248.1 | | 36.9 | % | | 181.2 | | 8.6 | % | | 166.8 | | | | 141.6 | | | (42.9 | )% | | 248.1 | | 36.9 | % | | 181.2 | |
| Other expenses | | | (200.3 | ) | | 25.2 | % | | (159.9 | ) | | 30.2 | % | | (122.8 | ) | | | (93.1 | ) | | (53.5) | % | | (200.3 | ) | | 25.3 | % | | (159.9 | ) |
| Total | | $ | 56.7 | | | * | | $ | (25.9 | ) | | * | | $ | 51.9 | | | $ | 51.9 | | | (8.5 | )% | $ | 56.7 | | | * | | $ | (26.1 | ) |
* Greater than 100%
| • | 2006 vs 2005 | Other revenues decreased $91.5 million due to lower power marketing activities, $10.8 million due to the termination of a contract to operate a steam combustion turbine at the United States Department of Energy (DOE) Savannah River Site and by $4.3 million due to lower carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project and lower management service fees of $10.0 million received by Primesouth, Inc., as discussed at Income Taxes -Recognition of Synthetic Fuel Tax Credits below. These decreases were partially offset by higher interest income of $9.4 million and higher third-party coal sales revenue of $4.8 million. Other expenses decreased by $90.6 million due to lower power marketing activities and $4.4 million due to the termination of the DOE’s Savannah River Site contract. These decreases were partially offset by increased charges of $8.7 million related to the settlement of the FERC power marketing matter (see Note 10 to the consolidated financial statements) and higher expenses to support third-party coal sales of $3.6 million. |
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.| • | 2005 vs 2004 | 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 $21.0 million loss on the sale of investments in Knology and ITC^DeltaCom. In 2004 impairments of $26.9 million were recorded on investments in Knology, ITC Holding and Magnolia Holding. Other revenues increased $42.8 million due to higher power marketing activity and $10.9 million due to carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project. Other expenses increased $43.1 million due to higher power marketing activity and $.8 million due to the charge associated with the FERC power marketing matter. (See Note 10 to the consolidated financial statements.) |
Interest Expense
Components of interest expense, excludingnet of the debt component of AFC, were as follows:
Millions of dollars | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Interest on long-term debt, net | | $ | 202.8 | | (2.5 | )% | $ | 208.1 | | 1.4 | % | $ | 205.2 | | | $ | 190.9 | | | (4.3 | )% | $ | 199.5 | | 0.7 | % | $ | 198.1 | |
| Other interest expense | | | 12.6 | | | * | | | 4.3 | | | (25.9 | )% | | 5.8 | | | | 18.7 | | | 48.4 | % | | 12.6 | | * | | | 4.3 | |
| Total | | $ | 215.4 | | | 1.4 | % | $ | 212.4 | | | 0.7 | % | $ | 211.0 | | | $ | 209.6 | | | (1.2 | )% | $ | 212.1 | | | 4.8 | % | $ | 202.4 | |
* Greater than 100%
| • | 2006 vs 2005 | Interest on long-term debt decreased primarily due to reduced long-term borrowings, partially offset by increased variable rates. Other interest expense increased primarily due to increased short-term borrowings. |
| • | 2005 vs 2004 | Interest on long-term debt decreasedincreased primarily due to the lower level of AFC resulting from reductions in the levels of capital expenditures subsequent to the completion of the Jasper County Electric Generation Station in May 2004 and the Lake Murray back-up dam project in May 2005, partially offset by the redemption of outstanding debt in late 2004. Other interest expense increased primarily due to increased short-term debtborrowings 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, exclusive of amounts related to the cumulative effect of an accounting change, increased in 2006 compared to 2005 by $237.6 million and decreased in 2005 compared to 2004 by $240.8 million and decreased $12.4 million in 2004 compared to 2003.million. 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 million 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.
Recognition of Synthetic Fuel Tax Credits
SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. Under an accounting plan approved by the Public Service Commission of South Carolina (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 back-up dam project. Under the accounting methodology approved by the SCPSC in a January 2005 order, 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 declines 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.The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2006 and 2005 are as follows:
| Millions of dollars | | 2006 | | 2005 | |
| | | | | | |
| Depreciation and amortization expense | | $ | (28.2 | ) | $ | (214.0 | ) |
| | | | | | | | |
| Income tax benefits: | | | | | | | |
| From synthetic fuel tax credits | | | 30.0 | | | 179.0 | |
| From accelerated depreciation | | | 10.8 | | | 81.8 | |
| From partnership losses | | | 7.8 | | | 28.9 | |
| Total income tax benefits | | | 48.6 | | | 289.7 | |
| | | | | | | | |
| Losses from Equity Method Investments | | | (20.4 | ) | | (75.7 | ) |
| | | | | | | | |
| Impact on Net Income | | | - | | | - | |
The 2005 amounts above reflect the recognition of previously deferred tax credits, while the 2006 amounts reflect the likelihood that credits available in 2006 will be phased down pursuant to regulations which limit the credits based on the relative commodity price of crude oil.
Depreciation on the Lake Murray back-up dam project 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 availability of 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 calculated portion of the credits would be available.
The benchmark price range for 2005, published in April 2006, was $53 to $67 per barrel, and no phase-out applied. However, SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2006 are likely to be impacted by the phase-out calculation. As such, in 2006 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 67% of credits generated will be available (phase-out of 33%). 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, there is significant uncertainty as to the continued availability of the credits in 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.
The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation, and total unrecovered cost at the end of December 31, 2007 may be significant. To the extent that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of December 31, 2006, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $69.1 million.
Finally, Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance services for a non-affiliated synthetic fuel production facility. Reduced synthetic fuel tax credit availability under the above phase-out provisions also adversely impacts the level of payment Primesouth receives for these services. The fees recognized by Primesouth in 2006 were $10.0 million lower than amounts recognized in 2005.
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 and to install equipment necessary to comply with environmental regulations, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, if requested.
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.
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. Ongeneration facilities. In February 10, 2006, SCE&G and Santee Cooper,the South Carolina Public Service Authority (Santee Cooper), a state-owned utility in South Carolina (joint owners of V. C. Summer Nuclear Station (Summer Station)), announced their selection of the Summer Station site as the preferred site for a new nuclear plantgeneration facilities should nuclearsuch generation be considered the best alternative in the future. Due to the significant lead time required for construction of a nuclear plant,generation facilities, the joint owners are preparing an application to the United States Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). that would cover two nuclear units. 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.generation facilities. The final decision to build a nuclear plantgeneration facilities will be influenced by several factors, including NRC licensing attainment, estimates of 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%55% at December 31, 2005. The Company’s goal is to reduce this leverage ratio to between 50% and 52%.2006. If the agencies rating the Company’s credit determine that the Company will not be able to achieve sufficient improvement in theCompany’s leverage ratio, among other measures, is too high, 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’sboth 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 requirementscapital expenditures for construction and nuclear fuel expenditures for 2006-2008,2007-2009, which are subject to continuing review and adjustment, are as follows:
Estimated Cash RequirementsCapital Expenditures
Millions of dollars | | 2006 | | 2007 | | 2008 | | | 2007 | | 2008 | | 2009 | |
| SCE&G: | | | | | | | | | | | | | | |
| Electric Plant: | | | | | | | | | | | | | | |
| Generation (including GENCO) | | $ | 128 | | $ | 86 | | $ | 193 | | | $ | 220 | | $ | 361 | | $ | 255 | |
| Transmission | | | 50 | | | 44 | | | 46 | | | | 45 | | | 52 | | | 35 | |
| Distribution | | | 115 | | | 114 | | | 115 | | | | 151 | | | 155 | | | 153 | |
| Other | | | 18 | | | 11 | | | 14 | | | | 28 | | | 38 | | | 17 | |
| Nuclear Fuel | | | 27 | | | 25 | | | 5 | | | | 55 | | | 6 | | | 26 | |
| Gas | | | 27 | | | 26 | | | 31 | | | | 50 | | | 59 | | | 52 | |
| Common | | | 22 | | | 17 | | | 7 | | |
| Other | | | 2 | | | - | | | - | | |
| Common and other | | | | 28 | | | 10 | | | 12 | |
| Total SCE&G | | | 389 | | | 323 | | | 411 | | | | 577 | | | 681 | | | 550 | |
| PSNC Energy | | | 70 | | | 78 | | | 84 | | |
| Other Companies Combined | | | 44 | | | 32 | | | 27 | | | | 151 | | | 160 | | | 142 | |
| Total | | $ | 503 | | $ | 433 | | $ | 522 | | | $ | 728 | | $ | 841 | | $ | 692 | |
The Company’s contractual cash obligations as of December 31, 20052006 are summarized as follows:
Contractual Cash Obligations
Millions of dollars | | Total | | Less than 1 year | | 1-3 years | | 4-5 years | | After 5 years | | | 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 | | | $ | 6,310 | | $ | 841 | | $ | 900 | | $ | 1,151 | | $ | 3,418 | |
| Capital leases | | | 2 | | 1 | | 1 | | - | | - | | | | 2 | | 1 | | 1 | | - | | - | |
| Operating leases | | | 53 | | 15 | | 35 | | 1 | | 2 | | | | 57 | | 30 | | 25 | | - | | 2 | |
| Purchase obligations | | | 166 | | 152 | | 12 | | 2 | | - | | | | 647 | | 348 | | | 296 | | 2 | | 1 | |
| Other commercial commitments | | | 8,955 | | | 1,633 | | | 2,207 | | | 1,124 | | | 3,991 | | | | 7,513 | | | 1,275 | | | 2,283 | | | 977 | | | 2,978 | |
| Total | | $ | 15,347 | | $ | 2,675 | | $ | 3,180 | | $ | 2,047 | | $ | 7,445 | | | $ | 14,529 | | $ | 2,495 | | $ | 3,505 | | $ | 2,130 | | $ | 6,399 | |
Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Many of these forwardForward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. Also included in other commercial commitments is a “take-and-pay” contract for natural gas which expires in 2019 and estimated obligations for coal and nuclear fuel purchases. See Note 10 to the consolidated financial statements.
Included in purchase obligations are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such 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$9.7 million in 2005,2006, 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 NYMEXNew York Mercantile Exchange (NYMEX) futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Company also has a legal obligation associated with the decommissioning and dismantling of Summer Station and other conditional asset retirement obligations that are not listed in the contractual cash obligations table. See Notes 1B and 1N10H 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.indebtedness. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.
Cash outlays for 2006 (estimated)(actual) and 2005 (actual)2007 (estimated) for certain expenditures are as follows:
Millions of dollars | | 2006 | | 2005 | | | 2006 | | 2007 | |
| Property additions and construction expenditures, net of AFC | | $ | 485 | | $ | 385 | | | $ | 527 | | $ | 673 | |
| Nuclear fuel expenditures | | | 18 | | | 18 | | | | 17 | | | 55 | |
| Investments | | | 18 | | | 18 | | | | 25 | | | 19 | |
| Total | | $ | 521 | | $ | 421 | | | $ | 569 | | $ | 747 | |
Financing Limits and Related Matters
The Company’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including state public service commissions and FERC. Descriptions of financing programs currently utilized by the Company follow.
Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC authority to issue short-term debt. Effective February 8, 2006 the FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 7, 2008.
At December 31, 20052006, 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 | | | SCANA | | SCE&G | | PSNC Energy | |
| Lines of credit (total and unused): | | | | | | | | | | | | | | |
| Committed | | | | | | | | |
| Short-term | | $ | 350 | | | - | | | - | | |
| Long-term (expires June 2010) | | | - | | $ | 525 | | $ | 125 | | |
| Committed long-term (expires December 2011) | | | $ | 200 | | $ | 650 | | $ | 250 | |
| Uncommitted | | | 103(a | ) | | 78(a | ) | | - | | | | 103 | (a) | | - | | | - | |
| Short-term borrowings outstanding: | | | | | | | | | | | | | | | | | | | | |
| Bank loans/commercial paper (270 or fewer days) | | $ | 25 | | $ | 303.1 | | $ | 98.6 | | | $ | - | | $ | 362.2 | | $ | 124.7 | |
| Weighted average interest rate | | | 4.43 | % | | 4.40 | % | | 4.47 | % | | | - | | | 5.38 | % | | 5.40 | % |
(a) SCANA or SCE&G may use $78 million of these lines of credit.
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, theThe Indenture under which they are issued contains no specific limit on the amount which may be issued.
South Carolina Electric & Gas Company
In September 2006 SCE&G’s First and Refunding Mortgage Bond Indenture,&G discharged its bond indenture dated January 1, 1945 (Old Mortgage) and coveringwhich covered 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.
properties. SCE&G is alsoremains subject to a bond indenture dated April 1, 1993 (New Mortgage)(Mortgage) covering substantially all of its electric properties under which all of its currently outstanding First Mortgage Bonds and all of its future mortgage-backed debt (New Bonds)(Bonds) has been and will be issued. New Bonds aremay be issued under the New Mortgage onin an aggregate principal amount not exceeding the basissum of a like(1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of Class Aretired Bonds issued under the Old Mortgage which have beenand (3) cash 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. Newtrustee. Bonds will be issuable under the New Mortgage only if adjusted net earningsAdjusted 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)Bonds and New Bonds to be outstanding (New Bond(Bond Ratio). For the year ended December 31, 2005,2006, the New Bond Ratio was 6.76.6.99.
SCE&G’s Restated Articles of Incorporation (the Articles)(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, 2005,2006, the Preferred Stock Ratio was 2.12.1.99.
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, 2005,2006, the ten percent test would have limited total issuances of unsecured indebtedness to approximately $419.5$428.4 million. Unsecured indebtedness at December 31, 2005,2006, totaled approximately $246.6$357.8 million, and was comprised primarily 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.
Financing Cash Flows
During 20052006 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$83 million primarily due to the payment of dividends.dividends, which were partially offset by net increases in long-term and short-term borrowings and proceeds from common stock issuances.
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, 2005,2006, the estimated fair value of the Company’s swaps totaled a $0.1 million (gain)gain related to combined notional amounts of $47.4$44.2 million.
In anticipation of the issuance of debt, the Company usesmay use interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, paymentsPayments received or made upon termination of such agreements are recorded within long-term debt on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bondsfirst mortgage bonds in May 2003,June 2006, SCE&G paid $11.9received approximately $8.8 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 startingan 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 belock. These proceeds are being amortized over the life of the related debt, to which it relates.thereby reducing its effective interest rate. As permitted by SFAS 104 “Statement of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions,” these proceeds have been classified as a financing activity in the consolidated statement of cash flows.
For additional information on significant financing transactions,activities, see Note 4 to the consolidated financial statements.
On February 16, 2006,15, 2007, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.42$.44 per share, an increase of 7.7%4.8%. The new dividend is payable April 1, 20062007 to stockholders of record on March 10, 2006.9, 2007.
Capital Expenditures
For the three years ended December 31, 2005,2006, the Company’s capital expenditures for environmental control totaled $200.2$160.2 million. These expenditures were in addition to expenditures included in “Other operation and maintenance” expenses, which were $28.7 million, $25.2 million, and $21.5 million during 2006, 2005 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$154.7 million for 20062007 and $314.3$494.8 million for the four-year period 20072008 through 2010.2011. These expenditures are included in the Company’s construction program,Estimated Capital Expenditures table, discussed in Liquidity and Capital Resources, and include the matters discussed below.
Electric Operations
In March 2005, the United States 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 installingbelieves that installation of additional air quality controls will be needed to meet the CAIR requirements. InstallationThe Company is reviewing the final rule. Compliance plans and operation and maintenance costs are currently being determined.cost to comply with the rule will be determined once the Company completes its review. Such costs are likely towill 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. TheAlthough the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is negotiating withuncertain as to how the South Carolina Department of Health and Environmental Control the terms of the state compliance proposals. InstallationPhase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls is likely towill be required to comply with the rule’s Phase II mercury rule’s emission caps. ComplianceFinal compliance plans and costs to comply with the rule will be determined once the Company completes its review and assessments.are still under review. Such costs are likely towill be material and are expected to be recoverable through rates.
The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the DOJUnited States Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the CAA.Clean Air Act (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 Companyindustry is not binding as precedent and the one favorable to the Companyindustry 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$450 million over the 2006-20092007-2010 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $4 million in 20092010 and $27 million in 20102011 and each subsequent years.year thereafter. To meet compliance requirements for the years 20112012 through 2015,2016, the Company anticipates additional capital expenditures totaling approximately $564$480 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(Nuclear Waste Act”)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 imposesimposed 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 $9 million settlement from DOE which requires the payment by DOE of $9 million to the plaintiffs.DOE. The payment is to reimbursereimbursed the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. SCE&G will recordrecorded its portion ($6 million) of the settlement as a reduction to its fuel costs. As a result, most of the credit will bewas 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.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates. 41
SCE&G has been named, along with 29 others, by the 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, purchase of new transformers and sale of used 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. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.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 andoperations. Such amounts 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$17.9 million at December 31, 20052006 and 2004, respectively.$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 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, byowns a decommissioned MGP site in 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 operationCalhoun Park area of Charleston, South Carolina. SCE&G anticipates that remediation for contamination at the site from 1967 to 1984. During that time,will be completed in late 2007, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2006, 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$22.3 million to date. SCE&G’s records indicated that only minimal quantitiesremediate the Calhoun Park site, and expects to spend an additional $1.1 million. In addition, the National Park Service of used transformers were shipped by itthe Department of the Interior made an initial demand 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 atfor payment of $9.1 million for certain costs and damages relating to 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. Anysite. SCE&G expects to recover any cost arising from the remediation of this matter is expected to be recoverablesite 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 2011. As of December 31, 2006, SCE&G has spent $4.8 million related to these three sites, and expects to spend an additional $11.2 million. SCE&G expects to recover any cost arising from the remediation of these sites 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$6.9 million, which reflects its estimated remaining liability at December 31, 2005.2006. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are $3.1$0.9 million. Management believes that all MGP cleanupPSNC Energy expects to recover any costs will be recoverableallocated to PSNC Energy arising from the remediation of these sites through gas rates.
Material retail rate proceedings are described in more detail in Note 2 to the consolidated financial statements.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters.
See earlier discussion of increase in retail electric and gas base rates during 2005 in Liquidity and Capital Resources.
In February 2005, theThe 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 $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.United States Congress passed the Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directing the U. S.United States Department of Transportation (DOT) to establish a pipeline integrity management rulethe 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 areis subject to imprecision, PSNC Energy currently estimates the total cost through December 2012 to be $8 million for the initial assessments, andnot including any subsequent remediation required through December 2012.that may be required. Effective November 1, 2004 the NCUC authorized the Company to deferdeferral accounting for subsequent rate consideration certain expenses incurred to comply with DOT’s pipeline integrity management requirements. In accordance with an October 2006 NCUC rate order, $1.4 million in costs incurred and deferred through June 30, 2006 are now being recovered through rates over a three-year period. Additionally, management believes that all subsequent costs will be recoverable by PSNC Energy through rates.
South Carolina PipelineGas Transmission Corporation
SCPCCGTC has approximately 5165 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 areis subject to imprecision, SCPCCGTC currently estimates the total cost to be $10$10.9 million for the initial assessments and any subsequent remediation required through December 2012.
Following are descriptions of the Company’s accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.
Utility Regulation
SCANA’s regulated utilities are subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” which require them to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations, liquidity or financial position of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. 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, 2005,2006, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $2.3 billion and $552$506 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 customercustomers 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, accountsAccounts receivable included unbilled revenues of $177.6 million at December 31, 2006 and $280.9 million and $213.0 million, respectively,at December 31, 2005, compared to total revenues of $4.6 billion for 20052006 and 2004 of $4.8 billion and $3.9 billion, respectively.for 2005.
Provisions for Bad Debts and Allowances for Doubtful Accounts
As of each balance sheet date, the Company evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of expected write-offs. These estimates are based on, among other things, comparisons of the relative age of accounts, assigned credit ratings for commercial and industrial accounts, credit scores for residential customers in Georgia when available, and consideration of actual write-off history. The distribution segments of the Company’s regulated utilities have established write-off histories and regulated service areas that tend to improve the recoverability of accounts and enable the utilities to reliably estimate their respective provisions for bad debts. The Company’s Retail Gas Marketing segment operates in Georgia’s deregulated natural gas market.market in which customers may obtain service from others without necessarily paying outstanding amounts and in which there are certain limitations on the Company’s ability to effect timely shut-off of service for nonpayment. As such estimation of the provision for bad debts related to this segmentfor these accounts is subject to greater imprecision.
Nuclear Decommissioning
Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Among the factors that could change SCE&G’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and timing of cash flows. Changes in any of these estimates could significantly impact the Company’s financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).
SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $357.3$451.0 million, stated in 1999 dollars. This estimate is2006 dollars, 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.Summer Station. The cost estimate is based on a decommissioning methodology acceptable to the NRC under whichassumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permitswould permit release for unrestricted use.
Under SCE&G’s method of funding decommissioning costs, fundsamounts collected through rates are invested in insurance policies on the lives of certain Company personnel. Amounts for decommissioningSCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferredexpenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies held by SCE&G to an external trust fund.the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
Accounting for Pensions and Other Postretirement Benefits
The Company follows SFAS 87, “Employers’ Accounting for Pensions,” as amended by SFAS 158, “Employees’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” in accounting for the cost of its defined benefit pension plan. The Company’s plan is fullyadequately funded and as such, net pension income is reflected in the financial statements (see Results of Operations)Operations-Pension Income). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension income of $18.1$13.5 million recorded in 20052006 reflects the use of a 5.75%5.60% discount rate and an assumed 9.25%9.00% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.5%5.35% in 20052006 would have increaseddecreased the Company’s pension income by approximately $0.4$1.1 million. Had the assumed long-term rate of return on assets been 9.0%8.75%, the Company’s pension income for 20052006 would have been reduced by approximately $2.1 million.
In determiningFor 2006, 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 within5.60% which was derived using a reasonable range of interest rates for obligations rated Aa by Moody’s as of January 1, 2005.cash flow matching technique. For 2006,2007, the discount rate to be used will be 5.6%5.85%, which was derived using athat same cash flow matching technique which the Company believes is preferable.technique. 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’ 20052006 review of the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 9.8%9.3%, 11.6%11.0%, 11.6%11.2% and 12.3%12.7%, respectively, all of which have been in excess of related broad indices. The 20052006 expected long-term rate of return of 9.25%9.0% was based on a target asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2006,2007, 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,” as amended by SFAS 158 in accounting for the cost of its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 5.75%5.60% and recorded a net SFAS 106 cost of $17.0$22.3 million for 2005.2006. Had the selected discount rate been 5.50%5.35%, the expense for 20052006 would have been $0.2$0.5 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.
The Company also adopted the balance sheet recognition provisions of SFAS 158 effective December 31, 2006, as more fully described in Note 3 to the consolidated financial statements. Asset Retirement Obligations
SFAS 143, “Accounting for Asset Retirement Obligations,”together with FINFinancial Accounting Standards Board Interpretation (FIN) 47,“Accounting for Conditional Asset Retirement Obligations,” provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates primarily to the Company’s regulated utility operations, adoption of SFAS 143 and FIN 47 hadhave no significant impact on results of operations. As of December 31, 2005,2006, the Company has recorded an ARO of approximately $132$93 million for nuclear plant decommissioning (as discussed above) and an ARO of approximately $191$199 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines, which waspipelines. The ARO for nuclear plant decommissioning reflects a reduction of $46 million from the corresponding ARO recorded under FIN 47.as of December 31, 2005. The reduction is primarily related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis. 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,time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s regulated utilities remains in place.
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,FIN 46(R), “Consolidation of Variable Interest Entities.” SCANA does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture 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.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 aboutsummarize 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 weighted average interest rates and related maturities. Fair values for debt and swaps represent quoted market prices.
| | Expected Maturity Date | Expected Maturity Date |
December 31, 2005 Millions of dollars | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | Fair Value | |
| Liabilities | | | | | | |
December 31, 2006 Millions of dollars | | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total | Fair Value |
| Long-Term Debt: | | | | | | | | | |
| Fixed Rate ($) | 174.4 | 68.6 | 158.6 | 143.6 | 43.6 | 2,524.6 | 3,113.4 | 3,108.8 | 33.2 | 123.2 | 108.2 | 14.8 | 619.3 | 2,023.6 | 2,922.3 | 3,020.0 |
| Average Fixed Interest Rate (%) | 8.50 | 6.96 | 6.13 | 6.39 | 6.99 | 6.14 | 6.47 | | 7.17 | 5.95 | 6.27 | 6.87 | 6.78 | 5.95 | 6.16 | |
| Variable Rate ($) | | | 100.0 | | | 100.0 | 100.0 | | 100.0 | | | 100.0 | 100.2 |
| Average Variable Interest Rate (%) | | | 4.56 | | | 4.56 | | | 5.52 | | | 5.52 | |
| Interest Rate Swaps: | | | | | | | | | |
| Pay Variable/Receive Fixed ($) | 3.2 | 28.2 | 3.2 | 6.4 | 47.4 | 0.1 | 28.2 | 3.2 | 3.2 | 44.2 | 0.1 |
| Average Pay Interest Rate (%) | 7.72 | 7.97 | 7.72 | 7.72 | 7.87 | | 8.50 | 8.55 | 8.55 | 8.52 | |
| Average Receive Interest Rate (%) | 8.75 | 7.11 | 8.75 | 8.75 | 7.77 | | 7.11 | 8.75 | 8.75 | 7.70 | |
| | Expected Maturity Date | Expected Maturity Date |
December 31, 2004 Millions of dollars | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | Fair Value | |
| Liabilities | | | | | | |
December 31, 2005 Millions of dollars | | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | Fair Value |
| Long-Term Debt: | | | | | | | | | |
| Fixed Rate ($) | 193.6 | 174.4 | 68.6 | 158.6 | 143.6 | 2,532.8 | 3,271.6 | 3,404.5 | 174.4 | 68.6 | 158.6 | 143.6 | 43.6 | 2,524.6 | 3,113.4 | 3,108.8 |
| Average Fixed Interest Rate (%) | 7.39 | 8.50 | 6.96 | 8.12 | 8.21 | 6.24 | 6.62 | | 8.50 | 6.96 | 6.13 | 6.39 | 6.99 | 6.14 | 6.47 | |
| Variable Rate ($) | | 200.0 | | | 200.0 | 200.0 | | 100.0 | | | 100.0 | 100.0 |
| Average Variable Interest Rate (%) | | 2.73 | | | 2.73 | | | 4.56 | | | 4.56 | |
| Interest Rate Swaps: | | | | | | | | | |
| Pay Variable/Receive Fixed ($) | 3.2 | 3.2 | 28.2 | 118.2 | 3.2 | 119.6 | 275.6 | 4.2 | 3.2 | 28.2 | 3.2 | 6.4 | 47.4 | 0.1 |
| Average Pay Interest Rate (%) | 5.74 | 5.74 | 6.04 | 4.73 | 5.74 | 4.46 | 4.78 | | 7.72 | 7.97 | 7.72 | 7.72 | 7.87 | |
| Average Receive Interest Rate (%) | 8.75 | 8.75 | 7.11 | 5.89 | 8.75 | 6.45 | 6.36 | | 8.75 | 7.11 | 8.75 | 8.75 | 7.77 | |
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 approximatelylong-term debt of $80 million at December 31, 2006 and $97 million and $94 million in long-term debt as ofat 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 $3.8 million.
Commodity Price Risk
Commodity price risk - The following table provides information aboutsummarizes the Company’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu.DT. Fair value represents quoted market prices.
| Expected Maturity: | | | | | | | |
| | | | | | Options |
| | Futures Contracts | | | Purchased Call | Purchased Put | Sold Put |
| 2006 | Long ($) | 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 | | | | | | | |
| Expected Maturity: | | | | | | | |
| | | | | | Options |
| | Futures Contracts | | | Purchased Call | Purchased Put | Sold Put |
| 2007 | Long | Short | | | (Long) | (Short) | (Long) |
| | | | | | | | |
| Settlement Price (a) | 6.76 | 6.57 | | Strike Price (a) | 9.08 | 10.89 | 6.17 |
| Contract Amount (b) | 37.0 | 4.3 | | Contract Amount (b) | 2.7 | 1.4 | 1.2 |
| Fair Value (b) | 28.8 | 3.0 | | Fair Value (b) | 0.1 | - | (0.1) |
| | | | | | | | |
| 2008 | | | | | | | |
| | | | | | | | |
| Settlement Price (a) | 8.31 | - | | Strike Price (a) | - | - | - |
| Contract Amount (b) | 10.3 | - | | Contract Amount (b) | - | - | - |
| Fair Value (b) | 9.8 | - | | Fair Value (b) | - | - | - |
| | | | | | | | |
| (a) Weighted average, in dollars | | | | | | |
| (b) Millions of dollars | | | | | | | |
| Swaps | 2006 | 2007 | | 2007 | 2008 | 2009 |
| | | | | | | |
| Commodity Swaps: | | | | | | |
| Pay fixed/receive variable ($) | 85.3 | 8.4 | | |
| Pay fixed/receive variable (b) | | 190.9 | 78.3 | 0.3 |
Average pay rate (a) | 11.254 | 8.955 | | 9.105 | 9.519 | 8.460 |
Average received rate (a) | 11.061 | 10.504 | | 6.948 | 8.475 | 8.447 |
| Fair Value (b) | | 145.7 | 69.7 | 0.3 |
| | | | | | |
| Pay variable/receive fixed ($) | 9.2 | - | |
| Pay variable/receive fixed (b) | | 0.9 | 0.8 | - |
Average pay rate (a) | 11.253 | - | 7.333 | 8.111 | - |
Average received rate (a) | 8.665 | - | 8.361 | 8.011 | - |
| Fair Value (b) | | 1.1 | 0.8 | - |
| | | | | | | |
| Basis Swaps: | | | | | | |
| Pay variable/receive variable ($) | 137.5 | - | | |
| Pay variable/receive variable (b) | | 14.1 | - | - |
Average pay rate (a) | 10.681 | - | | 6.331 | - | - |
Average received rate (a) | 10.660 | - | | 6.319 | - | - |
| Fair Value (b) | | 14.1 | - | - |
| | | | | | |
| | | | | | |
(a) Weighted average | | | |
| (a) Weighted average, in dollars | | | | |
| (b) Millions of dollars | | | | |
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 9 to the consolidated financial statements.
The NYMEX futures information above includes those financial positions of Energy Marketing, SCPCSCE&G 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’sSCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. 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 premiums, transaction fees, margin requirements 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.
ITEM 8.8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
SCANA Corporation:
We have audited the accompanying Consolidated Balance Sheetsconsolidated balance sheets of SCANA Corporation and subsidiaries (the “Company”) as of December 31, 20052006 and 2004,2005, and the related Consolidated Statementsconsolidated statements of Income, Changesincome, changes in Common Equitycommon equity and Comprehensive Incomecomprehensive income, and of Cash Flowscash flows for each of the three years in the period ended December 31, 2005.2006. 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, 20052006 and 2004,2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005,2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005,2006, 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,February 28, 2007 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, 2006February 28, 2007
SCANA Corporation
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 | |
December 31, (Millions of dollars) | | 2006 | | 2005 | |
Assets | | | | | |
| Utility Plant In Service | | $ | 9,227 | | $ | 8,999 | |
| Accumulated Depreciation and Amortization | | | (2,815 | ) | | (2,698 | ) |
| | | | 6,412 | | | 6,301 | |
| Construction Work in Progress | | | 326 | | | 175 | |
| Nuclear Fuel, Net of Accumulated Amortization | | | 39 | | | 28 | |
| Acquisition Adjustments | | | 230 | | | 230 | |
| Utility Plant, Net | | | 7,007 | | | 6,734 | |
| Nonutility Property and Investments: | | | | | | | |
| Nonutility property, net of accumulated depreciation of $70 and $62 | | | 132 | | | 108 | |
| Assets held in trust, net-nuclear decommissioning | | | 56 | | | 52 | |
| Other investments | | | 88 | | | 87 | |
| Nonutility Property and Investments, Net | | | 276 | | | 247 | |
| Current Assets: | | | | | | | |
| Cash and cash equivalents | | | 201 | | | 62 | |
| Receivables, net of allowance for uncollectible accounts of $14 and $25 | | | 655 | | | 881 | |
| Receivables-affiliated companies | | | 32 | | | 24 | |
| Inventories (at average cost): | | | | | | | |
| Fuel | | | 300 | | | 284 | |
| Materials and supplies | | | 93 | | | 79 | |
| Emission allowances | | | 22 | | | 54 | |
| Prepayments and other | | | 39 | | | 54 | |
| Deferred income taxes | | | 34 | | | 26 | |
| Total Current Assets | | | 1,376 | | | 1,464 | |
| Deferred Debits: | | | | | | | |
| Pension asset, net | | | 200 | | | 303 | |
| Emission allowances | | | 27 | | | - | |
| Regulatory assets | | | 792 | | | 617 | |
| Other | | | 139 | | | 154 | |
| Total Deferred Debits | | | 1,158 | | | 1,074 | |
| Total | | $ | 9,817 | | $ | 9,519 | |
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.
SCANA Corporation
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 | |
December 31, (Millions of dollars) | | 2006 | | 2005 | |
Capitalization and Liabilities | | | | | |
| Shareholders’ Investment: | | | | | | | |
| Common equity | | $ | 2,846 | | $ | 2,677 | |
| Preferred stock (Not subject to purchase or sinking funds) | | | 106 | | | 106 | |
| Total Shareholders’ Investment | | | 2,952 | | | 2,783 | |
| Preferred Stock, Net (Subject to purchase or sinking funds) | | | 8 | | | 8 | |
| Long-Term Debt, Net | | | 3,067 | | | 2,948 | |
| Total Capitalization | | | 6,027 | | | 5,739 | |
| Current Liabilities: | | | | | | | |
| Short-term borrowings | | | 487 | | | 427 | |
| Current portion of long-term debt | | | 43 | | | 188 | |
| Accounts payable | | | 414 | | | 471 | |
| Accounts payable-affiliated companies | | | 27 | | | 26 | |
| Customer deposits and customer prepayments | | | 85 | | | 70 | |
| Taxes accrued | | | 121 | | | 112 | |
| Interest accrued | | | 51 | | | 52 | |
| Dividends declared | | | 51 | | | 47 | |
| Other | | | 126 | | | 107 | |
| Total Current Liabilities | | | 1,405 | | | 1,500 | |
| Deferred Credits: | | | | | | | |
| Deferred income taxes, net | | | 947 | | | 940 | |
| Deferred investment tax credits | | | 120 | | | 121 | |
| Asset retirement obligations | | | 292 | | | 322 | |
| Postretirement benefits | | | 194 | | | 148 | |
| Regulatory liabilities | | | 714 | | | 605 | |
| Other | | | 118 | | | 144 | |
| Total Deferred Credits | | | 2,385 | | | 2,280 | |
| Commitments and Contingencies (Note 10) | | | - | | | - | |
| Total | | $ | 9,817 | | $ | 9,519 | |
See Notes to Consolidated Financial Statements.
SCANA Corporation
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.
SCANA Corporation
| | | | | | | | | | |
| | | | | | | 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 | |
Years Ended December 31, (Millions of dollars, except per share amounts) | | 2006 | | 2005 | | 2004 | | |
| Operating Revenues: | | | | | | | | |
| Electric | | $ | 1,877 | | $ | 1,909 | | $ | 1,688 | | |
| Gas-regulated | | | 1,257 | | | 1,405 | | | 1,126 | | |
| Gas-nonregulated | | | 1,429 | | | 1,463 | | | 1,071 | | |
| Total Operating Revenues | | | 4,563 | | | 4,777 | | | 3,885 | | |
| Operating Expenses: | | | | | | | | | | | |
| Fuel used in electric generation | | | 615 | | | 618 | | | 467 | | |
| Purchased power | | | 28 | | | 37 | | | 51 | | |
| Gas purchased for resale | | | 2,213 | | | 2,399 | | | 1,753 | | |
| Other operation and maintenance | | | 619 | | | 632 | | | 608 | | |
| Depreciation and amortization | | | 333 | | | 510 | | | 265 | | |
| Other taxes | | | 152 | | | 145 | | | 145 | | |
| Total Operating Expenses | | | 3,960 | | | 4,341 | | | 3,289 | | |
| | | | | | | | | | | | |
| Operating Income | | | 603 | | | 436 | | | 596 | | |
| | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | |
| Other revenues | | | 142 | | | 248 | | | 181 | | |
| Other expenses | | | (93 | ) | | (200 | ) | | (160 | ) | ) |
Interest charges, net of allowance for borrowed funds used during construction of $8, $3 and $10 | | | (209 | ) | | (212 | ) | | (202 | ) | ) |
| Gain (loss) on sale of investments and assets | | | 3 | | | 9 | | | (20 | ) | ) |
| Investment impairments | | | - | | | - | | | (27 | ) | ) |
| Preferred dividends of subsidiary | | | (7 | ) | | (7 | ) | | (7 | ) | ) |
| Allowance for equity funds used during construction | | | - | | | - | | | 16 | | |
| Total Other Expense | | | (164 | ) | | (162 | ) | | (219 | ) | ) |
| | | | | | | | | | | | |
Income Before Income Taxes (Benefit) and Earnings (Losses) from Equity Method Investments and Cumulative Effect of Accounting Change | | | 439 | | | 274 | | | 377 | | |
| Income Tax Expense (Benefit) | | | 119 | | | (118 | ) | | 123 | | |
| | | | | | | | | | | | |
| Income Before Earnings (Losses) from Equity Method Investments | | | | | | | | | | | |
| and Cumulative Effect of Accounting Change | | | 320 | | | 392 | | | 254 | | |
| Earnings (Losses) from Equity Method Investments | | | (16 | ) | | (72 | ) | | 3 | | |
| Cumulative Effect of Accounting Change, net of taxes | | | 6 | | | - | | | - | | |
| | | | | | | | | | | | |
| Net Income | | $ | 310 | | $ | 320 | | $ | 257 | | |
| | | | | | | | | | | | |
| Basic and Diluted Earnings Per Share of Common Stock: | | | | | | | | | | | |
| Before Cumulative Effect of Accounting Change | | $ | 2.63 | | $ | 2.81 | | $ | 2.30 | | |
| Cumulative Effect of Accounting Change, net of taxes | | | .05 | | | - | | | - | | |
| Basic and Diluted Earnings Per Share | | $ | 2.68 | | $ | 2.81 | | $ | 2.30 | | |
| | | | | | | | | | | | |
| Weighted Average Common Shares Outstanding (Millions) | | | 115.8 | | | 113.8 | | | 111.6 | | |
See Notes to Consolidated Financial Statements.
SCANA Corporation
For the Years Ended December 31, (Millions of dollars) | | 2006 | | 2005 | | 2004 | |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net Income | | $ | 310 | | $ | 320 | | $ | 257 | |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | | | | | | | | |
| Cumulative effect of accounting change, net of taxes | | | (6 | ) | | - | | | - | |
Excess losses (earnings), net of distributions from equity method investments | | | 23 | | | 72 | | | (3 | ) |
| Depreciation and amortization | | | 347 | | | 518 | | | 274 | |
| Amortization of nuclear fuel | | | 17 | | | 18 | | | 22 | |
| (Gain) loss on sale of assets and investments | | | (3 | ) | | (9 | ) | | 20 | |
| Impairment of investments | | | - | | | - | | | 27 | |
| Hedging activities | | | (15 | ) | | 4 | | | 11 | |
| Allowance for equity funds used during construction | | | - | | | - | | | (16 | ) |
| Carrying cost recovery | | | (7 | ) | | (11 | ) | | - | |
| Cash provided (used) by changes in certain assets and liabilities: | | | | | | | | | | |
| Receivables, net | | | 218 | | | (174 | ) | | (225 | ) |
| Inventories | | | (80 | ) | | (188 | ) | | (90 | ) |
| Prepayments and other | | | (2 | ) | | - | | | (2 | ) |
| Pension asset | | | (13 | ) | | (17 | ) | | (14 | ) |
| Other regulatory assets | | | (32 | ) | | (28 | ) | | (17 | ) |
| Deferred income taxes, net | | | 5 | | | 25 | | | 74 | |
| Regulatory liabilities | | | 9 | | | (159 | ) | | 48 | |
| Postretirement benefits obligations | | | (3 | ) | | 6 | | | 7 | |
| Accounts payable | | | (77 | ) | | 79 | | | 91 | |
| Taxes accrued | | | 9 | | | (20 | ) | | 23 | |
| Interest accrued | | | (1 | ) | | 1 | | | (4 | ) |
| Changes in fuel adjustment clauses | | | 3 | | | (7 | ) | | (3 | ) |
| Changes in other assets | | | 30 | | | (17 | ) | | 22 | |
| Changes in other liabilities | | | 21 | | | 54 | | | 77 | |
| Net Cash Provided From Operating Activities | | | 753 | | | 467 | | | 579 | |
| Cash Flows From Investing Activities: | | | | | | | | | | |
Utility property additions and construction expenditures, including debt AFC | | | (485 | ) | | (366 | ) | | (478 | ) |
| Proceeds from sale of assets and investments | | | 21 | | | 10 | | | 68 | |
| Nonutility property additions | | | (42 | ) | | (19 | ) | | (23 | ) |
| Investments | | | (25 | ) | | (18 | ) | | (20 | ) |
| Net Cash Used For Investing Activities | | | (531 | ) | | (393 | ) | | (453 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Proceeds from issuance of common stock | | | 79 | | | 84 | | | 65 | |
| Proceeds from issuance of debt | | | 132 | | | 221 | | | 136 | |
| Repayments of debt | | | (156 | ) | | (470 | ) | | (169 | ) |
| Redemption/repurchase of equity securities | | | - | | | (1 | ) | | (4 | ) |
| Dividends | | | (198 | ) | | (181 | ) | | (168 | ) |
| Short-term borrowings, net | | | 60 | | | 216 | | | 16 | |
| Net Cash Used For Financing Activities | | | (83 | ) | | (131 | ) | | (124 | ) |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | 139 | | | (57 | ) | | 2 | |
| Cash and Cash Equivalents, January 1 | | | 62 | | | 119 | | | 117 | |
| Cash and Cash Equivalents, December 31 | | $ | 201 | | $ | 62 | | $ | 119 | |
| Supplemental Cash Flow Information: | | | | | | | | | | |
| Cash paid for-Interest (net of capitalized interest of $8, $3 and $10) | | $ | 212 | | $ | 213 | | $ | 206 | |
| -Income taxes | | | 100 | | | 58 | | | 24 | |
| Noncash Investing and Financing Activities: | | | | | | | | | | |
| Unrealized loss on securities available for sale, net of tax | | | - | | | - | | | (2 | ) |
| Accrued construction expenditures | | | 54 | | | 36 | | | 49 | |
See Notes to Consolidated Financial Statements.
SCANA Corporation
| | | | | | | | | | |
| | | | | | | Accumulated | | | |
| | | | | | | Other | | | |
| | | Common Stock | | Retained | | Comprehensive | | | |
Millions | | Shares | | Amount | | Earnings | | Income (Loss) | | Total | |
| | | | |
| Balance as of December 31, 2003 | | | 111 | | $ | 1,187 | | $ | 1,113 | | $ | 6 | | $ | 2,306 | |
| Comprehensive Income: | | | | | | | | | | | | | | | | |
| Net Income | | | | | | | | | 257 | | | | | | 257 | |
| Changes in Other Comprehensive Income (Loss) net of taxes $(5) | | | | | | | | | | | | (10 | ) | | (10 | ) |
| 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 | |
| Changes in Other Comprehensive Income (Loss), net of taxes $- | | | | | | | | | | | | - | | | - | |
| 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 | |
| Comprehensive Income (Loss): | | | | | | | | | | | | | | | | |
| Net Income | | | | | | | | | 310 | | | | | | 310 | |
| Changes in Other Comprehensive Income (Loss), net of taxes $(8) | | | | | | | | | | | | (14 | ) | | (14 | ) |
| Total Comprehensive Income | | | | | | | | | 310 | | | (14 | ) | | 296 | |
| Deferred Cost of Employee Benefit Plans, net of taxes $(7) | | | | | | | | | | | | (11 | ) | | (11) | |
| Issuance of Common Stock | | | 2 | | | 79 | | | | | | | | | 79 | |
| Dividends Declared on Common Stock | | | | | | | | | (195 | ) | | | | | (195 | ) |
| Balance as of December 31, 2006 | | | 117 | | $ | 1,411 | | $ | 1,464 | | $ | (29 | ) | $ | 2,846 | |
The Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other comprehensive income gains, losses, prior service costs and credits that have not yet been recognized through net periodic benefit cost, net of tax effects.
See Notes to Consolidated Financial Statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A.Organization and Principles of Consolidation
SCANA Corporation (SCANA, and together with its consolidated subsidiaries, the Company), a South Carolina corporation, is a holding company. The Company through wholly owned subsidiaries, is engagedengages 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 inconducts 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 PipelineGas Transmission Corporation (SCPC)(CGTC) | SCANA Resources, Inc. |
SCG Pipeline, Inc. | SCANA Services, Inc. |
| | SCANA Corporate Security Services, Inc. |
Effective November 1, 2006, CGTC began operating as an open access, transportation-only interstate pipeline company. CGTC resulted from the merger of SCG Pipeline, Inc. into South Carolina Pipeline Corporation (SCPC), both of which were wholly owned subsidiaries of SCANA. SCPC was subsequently renamed CGTC.
CertainThe Company reports 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 tothe regulatory assets and regulatory liabilities summarized as 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 | ) |
| | | December 31, | |
| Millions of dollars | | 2006 | | 2005 | |
Regulatory Assets: | | | |
| Accumulated deferred income taxes | | $ | 174 | | $ | 177 | |
| Under-collections-electric fuel and gas cost adjustment clauses | | | 95 | | | 61 | |
| Purchased power costs | | | 9 | | | 17 | |
| Environmental remediation costs | | | 29 | | | 28 | |
| Asset retirement obligations and related funding | | | 264 | | | 250 | |
| Franchise agreements | | | 55 | | | 56 | |
| Regional transmission organization costs | | | 8 | | | 11 | |
| Deferred employee benefit plan costs | | | 142 | | | - | |
| Other | | | 16 | | | 17 | |
| Total Regulatory Assets | | $ | 792 | | $ | 617 | |
| | | December 31, | |
| Millions of dollars | | 2006 | | 2005 | |
Regulatory Liabilities: | | | | | | | |
| Accumulated deferred income taxes | | $ | 38 | | $ | 39 | |
| Over-collections-electric fuel and gas cost adjustment clauses | | | 8 | | | 20 | |
| Other asset removal costs | | | 599 | | | 488 | |
| Storm damage reserve | | | 44 | | | 38 | |
| Planned major maintenance | | | 6 | | | 9 | |
| Other | | | 19 | | | 11 | |
| Total Regulatory Liabilities | | $ | 714 | | $ | 605 | |
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-electricUnder- and over-collections-electric fuel and gas cost adjustment clauses, net, represent amounts under-collectedunder- or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings. Included in these amounts are regulatory assets or liabilities arising from the natural gas hedging programs of the Company’s regulated operations. See Note 1F.Notes 1E and 1L.
Deferred purchasedPurchased power costs-represents costs that wererepresents costs 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 yearthree-year period beginning January 2005.
Deferred environmentalEnvironmental 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$17.9 million remain to be recovered. A portion of the costs incurred at sites owned byThrough June 30, 2006, PSNC Energy has been recovered through rates. Amounts incurred and deferred $3.6 million in costs, net of insurance settlements, that arewere not currently being recovered by PSNC Energythrough rates. In connection with an October 2006 NCUC rate order, such costs are now being recovered through rates are approximately $3.1 million. Managementover a three-year period. In addition, management believes that these costs incurred subsequent to June 30, 2006, totaling $0.9 million at December 31, 2006, and the estimated remaining costs of approximately $7.4$6.9 million, will be recoverable by PSNC Energy.Energy through rates.
Asset retirement obligations (ARO) and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) and conditional AROs recorded as required by SFAS 143, “Accounting for Asset Retirement Obligations,” and Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations.”
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. TheseSCE&G is amortizing these amounts are being amortized through cost of service rates and are expected to be amortized over approximately 1520 years.
Deferred regionalRegional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. Effective January 2005, the SCPSC approved the amortization of these amounts through cost of service rates over approximately five years.
Deferred employee benefit plan costs represent amountsof pension and other postretirement benefit costs which were accrued as liabilities under provisions of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” but which are expected to be recovered through utility rates (see Note 3).
Other asset removal costs represent net collections through depreciation rates of estimated costs to be incurred for the removal of assets in the future.
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 incurred, as approved through specific SCPSC orders. SCE&G is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle and are a component of cost of service and do not receive special rate consideration.
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 ofjointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G’s portion of Summer Station was $1.0 billion as of December 31, 20052006 and 20042005 (including amounts related to ARO). Accumulated depreciation associated with SCE&G’s share of Summer Station was $478.7$496.8 million and $463.7$478.7 million as of December 31, 20052006 and 2004,2005, respectively (including amounts related to ARO). SCE&G’s share of the direct expenses associated with operating Summer Station is included in “Otherother operation and maintenance”maintenance expenses and totaled $77.7 million for 2006, $76.3 million for 2005 and $74.5 million and $74.7 million for the years ended December 31, 2005, 2004 and 2003, respectively.2004.
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 collectcollecting $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2005,2006, SCE&G incurred $4.9$7.2 million for turbine maintenance. The remaining $3.6$1.3 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$1.0 million per month from January 2004July 2005 through June 2005December 2006 for its portion of the outage in April 2005October 2006 and is accruing $1.0$1.1 million per month for its portion of the outage scheduled for October 2006.the spring of 2008. Total costs for the 20052006 outage were $22.3$25.5 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$17.0 million. As of December 31, 20052006 and 2004,2005, SCE&G had accrued $0.2 million and $5.7 million, and $9.9 million, respectively.
E.D. Allowance for Funds Used During Construction (AFC)
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using composite rates of 4.9%5.5%, 4.9% and 6.9% for 2006, 2005 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. InterestSCE&G capitalizes interest on nuclear fuel in process is capitalized at the actual interest amount incurred.
F.E. Revenue Recognition
Revenues are recordedThe Company records revenues during the accounting period in which it provides services are provided to customers and includeincludes estimated amounts for electricity and natural gas delivered, but not yet billed. Unbilled revenues totaled $177.6 million at December 31, 2006 and $280.9 million and $213.0 million as ofat December 31, 2005 and 2004, respectively.2005.
Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel costThis 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$28.9 million and $6.0$44.1 million at December 31, 20052006 and 2004,2005, 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, 20052006 and 2004,2005, SCE&G had undercollected (overcollected) $11.8$20.3 million and $(7.8)$11.8 million, respectively, which amounts are also included in other regulatory assets or liabilities.assets. At December 31, 2006 and 2005, PSNC Energy had overcollected $(15.1)undercollected $38.5 million, net, and overcollected $15.1 million, net, respectively, which also isamounts are included in other regulatory assets or 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.F. Depreciation and Amortization
ProvisionsThe Company records 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 | | | 2006 | | 2005 | | 2004 | |
| SCE&G | | | 3.20 | % | | 2.99 | % | | 3.02 | % | | | 3.19 | % | | 3.20 | % | | 2.99 | % |
| GENCO | | | 2.66 | % | | 2.66 | % | | 2.66 | % | | | 2.66 | % | | 2.66 | % | | 2.66 | % |
| SCPC | | | 2.01 | % | | 2.04 | % | | 2.13 | % | |
| CGTC | | | | 2.04 | % | | 2.01 | % | | 2.04 | % |
| PSNC Energy | | | 3.77 | % | | 3.87 | % | | 4.05 | % | | | 3.69 | % | | 3.77 | % | | 3.87 | % |
| Aggregate of Above | | | 3.20 | % | | 3.04 | % | | 3.10 | % | | | 3.19 | % | | 3.20 | % | | 3.04 | % |
For SCE&G records nuclear fuel amortization using 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.
units-of-production method. 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.retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the Department of Energy (DOE) under a contract for disposal of spent nuclear fuel.
The Company considers amounts categorized by FERC as “acquisition adjustments” to be goodwill as defined in SFAS 142, “Goodwill and Other Intangible Assets,” and has ceased amortization of such amounts. These amounts are related to acquisition adjustments of approximately $466 million ($210 million net of accumulated amortization) million recorded on the books ofby PSNC Energy (Gas Distribution segment) and approximately $40 million ($20 million net of accumulated amortization) recorded on the books of SCPCby CGTC (Gas Transmission segment). In accordance with SFAS 142, the Company performs an annual impairment evaluation of its investment in PSNC Energy and SCPC.CGTC. 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 2002.2006 and 2005. Should a write-down be required in the future, such a charge would be treated as an operating expense.
H.G. Nuclear Decommissioning
SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $357.3$451.0 million, stated in 19992006 dollars, based on a decommissioning study completed in 2000.2006. 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 whichassumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permitswould permit release for unrestricted use.
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2006, 2005 2004 and 2003)2004) are invested in insurance policies on the lives of certain Company personnel. AmountsSCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by SCE&G to an external trust fund.expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
I.H. Income and Other Taxes
The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense.
The Company records excise taxes billed and collected, as well as local franchise and similar taxes, as liabilities until they are remitted to the respective taxing authority. Accordingly, no such taxes are included in revenues or expenses in the statements of income.
J.I. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-termThe Company records long-term debt premium and discount are recorded in long-term debt and are amortizedamortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and amortized over the term of the replacement debt.
K.J. 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.K. Cash and Cash Equivalents
The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and notes.
M.L. Commodity Derivatives
The Company records derivatives contracts at their fair value in accordance with SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and adjusts fair value each reporting period. The Company determines fair value of most of the energy-related derivatives contracts using quotations from markets where they are actively traded. For other derivatives contracts, the Company uses published market surveys and, in certain cases, 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’sThe Company’s regulated gas operations (SCE&G and PSNC Energy) hedge gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options. SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC’sthese hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizesutilized to hedge its gas purchasing activities are recoverable through itsthe 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’sEnergy's tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the overover- or under recoveryunder-recovery of gas costs.
N.M. New Accounting StandardsMatters
SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaced SFAS 123, “Accounting for Stock-Based Compensation,” and superseded Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees.” The Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the Company’s results of operations is discussed at Note 3.
The Company adopted SFAS 154, “Accounting Changes and Error Corrections,” was issued in June 2005. Itthe first quarter of 2006. SFAS 154 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) OpinionAPB 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,Statements.” although it carries forward someThe adoption 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 materialhad no 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.
| 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),157, “Share-Based Payment,Fair Value Measurements,” 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-dateSeptember 2006. SFAS 157 establishes a framework for measuring fair value ofto increase the instruments issued. Compensation cost will be recognized over the period that an employee provides serviceconsistency and comparability 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.”fair value measurements. The Company plans towill adopt SFAS 123(R)157 in the first quarter of 20062008, 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.In September 2006, SFAS 158, “Equity Compensation PlanEmployers' Accounting for Defined Benefit Pension and Other Postretirement Plans,” amended SFAS 87 and SFAS 106 to require recognition of the overfunded or underfunded status of pension and other postretirement benefit plans on the balance sheet. Under SFAS 158, gains and losses, prior service costs and credits, and any remaining transition amounts under SFAS 87 and SFAS 106 that have not yet been recognized through net periodic benefit cost are to be recognized in accumulated other comprehensive income, net of tax effects, until they are amortized as a component of net periodic cost. The Company adopted SFAS 158 as of December 31, 2006. Because a significant amount of the Company’s pension and other postretirement costs recorded under SFAS 87 and SFAS 106 are attributable to employees in its regulated operations, the adoption of SFAS 158 primarily resulted in the recording of additional regulatory assets. The impact of adoption on the Company’s financial position is detailed at Note 3. The adoption did not have an impact on the Company’s results of operations or cash flows.
Under the SCANA Corporation Long-Term Equity Compensation Plan (the Plan),SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain employeesother assets and non-employee directors may receive incentive and nonqualified stock options and other forms of equity-based compensation.liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company accountshas not determined what impact, if any, that adoption will have on the Company’s results of operations, cash flows or financial position.
FIN 48, “Accounting for this equity-based compensation usingUncertainty in Income Taxes,” was issued in June 2006. FIN 48 clarifies the intrinsic value method under APB 25, accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109,“Accounting for Stock IssuedIncome Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to Employees,”be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and related interpretations. In addition,penalties, accounting in interim periods, disclosure and transition. The Company will adopt FIN 48 in the Company has adoptedfirst quarter of 2007, and does not expect that the disclosure provisionsinitial adoption will have a material impact on the Company’s results of SFAS 123,operations, cash flows or financial position.
FASB Staff Position (FSP) AUG AIR-1 “Accounting for Stock-Based Compensation,Planned Major Maintenance Activities,” was issued in September 2006, and SFAS 148 amends APB 28, ““AccountingInterim Financial Reporting,” to prohibit the use of the accrue-in-advance method of accounting for Stock-Based Compensation-Transitionplanned major maintenance in annual and Disclosure.”
Options, allaccrue-in-advance accounting for certain planned major maintenance activities. Accordingly, the Company will follow SFAS 71 when accounting for these activities. The Company will adopt FSP AUG AIR-1 in the first quarter of which were granted prior to 2005,2007, and all of which were fully vested as of December 31, 2005, were granted with exercise prices equal todoes not expect that the fair market value of SCANA’s common stockinitial adoption will have a material impact 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 issuanceCompany’s results 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:operations, cash flows or financial position.
| | | 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 United States Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin 108 (SAB 108) in September 2006. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying and assessing the materiality of current year misstatements. SAB 108 also provides transition guidance for correcting errors existing from prior years. The Company also grants other formsadopted SAB 108 in December 2006. The adoption had no impact on the Company’s results 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.operations, cash flows or financial position.
P.N. 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.O. 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$31.8 million and $18.6$24.6 million at December 31, 20052006 and 2004,2005, respectively. SCE&G had recorded as payables to these affiliated companies approximately $25.3$26.6 million and $17.8$25.3 million at December 31, 20052006 and 2004,2005, respectively. SCE&G purchased approximately $291.1 million, $248.1 million $190.6 million and $145.8$190.6 million of synthetic fuel from these affiliated companies in 2006, 2005 and 2004, and 2003, respectively.
Summarized combined financial informationThe Company received cash distributions from equity investees of unconsolidated affiliates as$6.7 million in 2006, $7.1 million in 2005 and $7.3 million in 2004. The Company made cash investments in equity investees of $18.4 million in 2006, $17.7 million in 2005 and for the years ended December 31, 2005, 2004 and 2003, is presented below:$18.7 million in 2004.
| | | 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 | ) |
R. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.
S.P. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. RATE AND OTHER REGULATORY MATTERS
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 Damback-up dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.
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 2006, 2005 2004 or 2003.2004.
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 20052006 and 20042005 was as follows:
Rate Per KWh | Effective Date |
$.01678 | January-April 2004 |
$.01821 | May-December 2004 |
$.01764 | January-April 2005 |
| $.02256 | May 2005-April 2006 |
| $.02516 | May-December 20052006 |
In connection with the May 2006 fuel component increase, SCE&G agreed to spread the recovery of previously undercollected fuel costs of $38.5 million over a two-year period.
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.
In June 2006, SCE&G reported to the SCPSC that its return on common equity for the twelve months ended March 31, 2006 was more than 0.5% below the allowed return, and as provided under South Carolina’s Natural Gas Rate Stabilization Act, SCE&G requested an annualized increase in certain natural gas base rates. In September 2006, the SCPSC approved an annual increase of $17.4 million. The rate adjustment was effective with the first billing cycle in November 2006. 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 wascomponents by class were as follows:follows (rate per therm):
Rate Per Therm
| Effective Date
|
$.877 | January-October 2004 |
$.903 | November 2004-October 2005 |
| Effective Date | | Residential | | Small/Medium | | Large | |
| January-October 2005 | | | $.903 | | | $.903 | | | $.903 | |
| November 2005 | | | 1.297 | | | 1.222 | | | 1.198 | |
| December 2005 | | | 1.362 | | | 1.286 | | | 1.263 | |
| January 2006 | | | 1.297 | | | 1.222 | | | 1.198 | |
| February-October 2006 | | | 1.227 | | | 1.152 | | | 1.128 | |
| November 2006 | | | 1.115 | | | 1.004 | | | .963 | |
| December 2006 | | | 1.240 | | | 1.130 | | | 1.090 | |
In October 20052006, the SCPSC approved an increasea reduction in SCE&G’sthe cost of gas component from a rate of $.903 per therm for all customer classes toSCE&G’s retail natural gas 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, theThe SCPSC approved an increase in thealso authorized SCE&G to adjust its 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.on a monthly, rather than an annual, basis beginning in December 2006.
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 deferdefers certain MGP environmental costs in regulatory asset accounts and collectcollects and amortizeamortizes these costs through base rates.
Public Service Company of North Carolina, Incorporated (PSNC Energy)
PSNC Energy'sEnergy’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- collectionsunder-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy'sEnergy’s gas purchasing practices annually.
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 was as follows:
| Rate Per Therm | Effective Date |
| $.825 | January 2005 |
| .725 | February-July 2005 |
| .825 | August-September 2005 |
| 1.100 | October 2005 |
| 1.275 | November-December 2005 |
| 1.075 | January 2006 |
| .875 | February 2006 |
| .825 | March-December 2006 |
In January 2007, the NCUC approved PSNC Energy’s request to decease the benchmark cost of gas from $1.075$0.825 per therm to $.825$0.750 per therm for service rendered on and after MarchJanuary 1, 2006.2007.
In October 2006, the NCUC granted PSNC Energy an annual increase in retail natural gas margin revenues of approximately $15.2 million, or 2.6%, which was offset by a $9.2 million decrease in fixed-gas cost revenues, for an overall increase of $6 million, or 1.0%. The new rates are based on an allowed overall rate of return of 8.9%, and became effective with the first billing cycle in November 2006. In connection with the rate increase, the NCUC approved PSNC Energy’s recovery through rates, over a three-year period, of certain costs for environmental remediation and pipeline integrity management.
In September 2006, in connection with PSNC Energy’s 2006 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the twelve-month review ended March 31, 2006.
In March 2006, the NCUC authorized PSNC Energy to place pipeline supplier refunds that it presently holds and future supplier refunds into the appropriate deferred accounts for the over- or under-recovery of gas costs. Prior to this authorization, refunds from PSNC Energy’s interstate pipeline transporters were placed in a state-approved expansion fund to provide financing for expansion into areas that otherwise would not be economically feasible to serve. In December 2006, PSNC Energy received a disbursement of $1.1 million from the state expansion fund upon completion of a project to expand natural gas service to Louisburg, North Carolina.
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.
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 PipelineGas Transmission Corporation
SCPC's purchased gas adjustmentIn July 2006, FERC approved the application for cost recoverymerger of SCG Pipeline, Inc., into SCPC. SCPC was renamed CGTC. The merger was finalized 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.CGTC commenced operations as an open access transportation-only interstate pipeline company on November 1, 2006.
3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension and Other Postretirement Benefit Plans
The Company sponsors a noncontributory defined benefit pension plan, covering substantially all permanent employees. The Company's policy has been to fund the plan to the extent permitted by applicable federal income tax regulations as determined by an independent actuary.
Effective July 1, 2000 the Company's pension plan, which provided a final average pay formula, was amended to provide a cash balance formula for employees hired before January 1, 2000 who elected that option and for all new employees.employees hired on or after January 1, 2000. For employees who elected to remain under the final average pay formula, benefits are based on years of credited service and the employee's average annual base earnings received during the last three years of employment. For employees under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits.
In addition to pension benefits, the Company provides certain unfunded postretirement health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.
The Company adopted the balance sheet recognition provisions of SFAS 158 at December 31, 2006. The incremental effect of applying SFAS 158 on individual line items in the balance sheet was as follows:
| | | Before | | | | After | |
| | | Application of | | | | Application of | |
December 31, 2006 | | SFAS 158 | | Adjustments | | SFAS 158 | |
| | | Millions of dollars | |
| Deferred debits - pension asset, net | | $ | 316.7 | | $ | (117.2 | ) | $ | 199.5 | |
| Deferred debits - regulatory assets | | | 649.9 | | | 142.4 | | | 792.3 | |
| Deferred debits - other | | | 137.9 | | | 1.6 | | | 139.5 | |
| Total deferred debits | | | 1,131.2 | | | 26.8 | | | 1,158.0 | |
| Total assets | | | 9,790.2 | | | 26.8 | | | 9,817.0 | |
| Common equity | | | 2,855.8 | | | (9.8 | ) | | 2,846.0 | |
| Total shareholders’ investment | | | 2,962.0 | | | (9.8 | ) | | 2,952.2 | |
| Total capitalization | | | 6,036.5 | | | (9.8 | ) | | 6,026.7 | |
| Current liabilities - other | | | 112.2 | | | 13.7 | | | 125.9 | |
| Total current liabilities | | | 1,391.5 | | | 13.7 | | | 1,405.2 | |
| Deferred credits - deferred income taxes, net | | | 953.1 | | | (6.4 | ) | | 946.7 | |
| Deferred credits - postretirement benefits | | | 158.2 | | | 35.8 | | | 194.0 | |
| Deferred credits - other | | | 124.8 | | | (6.5 | ) | | 118.3 | |
| Total deferred credits | | | 2,362.1 | | | 22.9 | | | 2,385.0 | |
| Total capitalization and liabilities | | | 9,790.2 | | | 26.8 | | | 9,817.0 | |
Funded Status
The funded status at the end of the year and the related amounts recognized on the balance sheets follow:
| | | Pension Benefits | | Other Postretirement Benefits | |
| | | December 31, | | December 31, | |
| | | 2006 | | 2005 | | 2006 | | 2005 | |
| | | Millions of Dollars | |
| Fair value of plan assets | | $ | 912.5 | | $ | 854.3 | | | - | | | - | |
| Benefit obligations | | | 713.0 | | | 711.4 | | $ | 206.9 | | $ | 202.1 | |
| Funded status | | | 199.5 | | | 142.9 | | | (206.9 | ) | | (202.1 | ) |
| Unrecognized net actuarial loss | | | n/a | | | 88.4 | | | n/a | | | 44.4 | |
| Unrecognized prior service cost | | | n/a | | | 71.3 | | | n/a | | | 5.2 | |
| Unrecognized transition obligation | | | n/a | | | 0.6 | | | n/a | | | 4.3 | |
| Amount recognized, end of year | | $ | 199.5 | | $ | 303.2 | | $ | (206.9 | ) | $ | (148.2 | ) |
Amounts recognized on the balance sheets consist of:
| Noncurrent asset | | $ | 199.5 | | | n/a | | | - | | | n/a | |
| Current liability | | | - | | | n/a | | $ | (12.9 | ) | | n/a | |
| Noncurrent liability | | | - | | | n/a | | | (194.0 | ) | | n/a | |
| Prepaid benefit cost | | | n/a | | $ | 303.2 | | | n/a | | | n/a | |
| Accrued benefit cost | | | n/a | | | - | | | n/a | | $ | (148.2 | ) |
Deferred amounts recognized in accumulated other comprehensive income, which is a component of common equity, as of December 31, 2006, including the adjustment above to reflect the adoption of SFAS 158, were as follows:
December 31, 2006 | | Pension Benefits | | Other Postretirement Benefits | | Total | |
| | | | | | | Millions of dollars | |
| Transition Obligation | | | - | | $ | 0.6 | | $ | 0.6 | |
| Prior Service Costs | | $ | 0.9 | | | 0.6 | | | 1.5 | |
| Actuarial Losses | | | 6.6 | | | 2.4 | | | 9.0 | |
| Total | | $ | 7.5 | | $ | 3.6 | | $ | 11.1 | |
The estimated transition obligation, prior service costs and actuarial losses for the defined benefit plans that will be amortized from accumulated other comprehensive income into net periodic benefit costs during 2007 are less than $300,000 in aggregate.
Changes in Benefit Obligations
The measurement date used to determine pension and other postretirement benefit obligations is December 31.
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 | | | Retirement Benefits | | Other Postretirement Benefits | |
| | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Benefit obligation, January 1 | | $ | 669.5 | | $ | 619.9 | | $ | 197.5 | | $ | 188.4 | | | $ | 711.5 | | $ | 669.5 | | $ | 202.1 | | $ | 197.5 | |
| Service cost | | | 12.2 | | | 11.1 | | | 3.5 | | | 3.3 | | | | 14.0 | | | 12.2 | | | 4.6 | | | 3.5 | |
| Interest cost | | | 38.3 | | | 37.4 | | | 10.7 | | | 11.4 | | | | 39.8 | | | 38.3 | | | 11.5 | | | 10.7 | |
| Plan participants' contributions | | | - | | | - | | | 2.3 | | | 1.1 | | | | - | | | - | | | 2.1 | | | 2.3 | |
| Plan amendments | | | - | | | 8.0 | | | (0.3 | ) | | 4.7 | | | | 0.6 | | | - | | | 4.0 | | | (0.3 | ) |
| Actuarial loss | | | 27.1 | | | 24.1 | | | 1.5 | | | 1.2 | | |
| Actuarial (gain) loss | | | | (14.4 | ) | | 27.1 | | | (5.5 | ) | | 1.5 | |
| Benefits paid | | | (35.6 | ) | | (31.0 | ) | | (13.1 | ) | | (12.6 | ) | | | (38.5 | ) | | (35.6 | ) | | (11.9 | ) | | (13.1 | ) |
| Benefit obligation, December 31 | | $ | 711.5 | | $ | 669.5 | | $ | 202.1 | | $ | 197.5 | | | $ | 713.0 | | $ | 711.5 | | $ | 206.9 | | $ | 202.1 | |
The accumulated benefit obligation for retirement benefits at the end of 2006 and 2005 and 2004 was $664.4$666.6 million and $635.8$664.4 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 | | | 2006 | | 2005 | |
| Annual discount rate used to determine benefit obligations | | | 5.60 | % | | 5.75 | % | | | 5.85 | % | | 5.60 | % |
| Assumed annual rate of future salary increases for projected benefit obligation | | | 4.00 | % | | 4.00 | % | | | 4.00 | % | | 4.00 | % |
A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005.2006. The rate was assumed to decrease gradually to 5.0% for 20122013 and to remain at that level thereafter. The effects of a one percentage point increase or decrease in the annual rate 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 | ) |
| | | 1% Increase | | 1% Decrease | |
| | | Millions of dollars | |
| Effect on postretirement benefit obligation | | $ | 3.1 | | $ | (2.7 | ) |
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.
Changes in Plan Assets
| | | Retirement Benefits | | | Retirement Benefits | |
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Fair value of plan assets, January 1 | | $ | 846.7 | | $ | 787.7 | | | $ | 854.3 | | $ | 846.7 | |
| Actual return on plan assets | | | 43.2 | | | 90.0 | | | | 96.7 | | | 43.2 | |
| Benefits paid | | | (35.6 | ) | | (31.0 | ) | | | (38.5 | ) | | (35.6 | ) |
| Fair value of plan assets, December 31 | | $ | 854.3 | | $ | 846.7 | | | $ | 912.5 | | $ | 854.3 | |
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. At the end of 20052006 and 2004,2005, 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, 20052006 and 2004,2005, the Company recorded within deferred credits a $10.2$3.6 million and $9.7$10.2 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, 20052006 and 2004,2005, the Company also recorded within deferred debits a $7.1$9.9 million and $6.8$7.1 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* | | | | Other Postretirement Benefits* | |
Expected Benefit Payments | Pension Benefits | Excluding Medicare Subsidy | Including Medicare Subsidy | | Pension Benefits | | Excluding Medicare Subsidy | | Including Medicare Subsidy | |
| | Millions of dollars | | Millions of dollars | |
| | | | | | | | | | | |
| 2006 | $35.9 | $11.3 | $10.9 | |
| 2007 | 37.7 | 12.1 | 11.7 | | $ | 39.7 | | $ | 13.3 | | $ | 12.9 | |
| 2008 | 39.6 | 12.8 | 12.3 | | | 40.1 | | | 13.6 | | | 13.2 | |
| 2009 | 41.6 | 13.2 | 12.7 | | | 40.5 | | | 13.6 | | | 13.2 | |
| 2010 | 43.6 | 13.7 | 13.2 | | | 40.9 | | | 14.1 | | | 13.7 | |
| 2011-2015 | 253.5 | 72.8 | 70.6 | |
| 2011 | | | | 41.3 | | | 14.3 | | | 13.9 | |
| 2012-2016 | | | | 212.8 | | | 76.2 | | | 74.2 | |
*Net of participant contributions
Net Periodic Cost
As allowed by SFAS 87 and SFAS 106, as amended, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans under SFAS 132, “Employer's Disclosures about Pensions and Other Postretirement Benefits” as amended, are set forth in the following tables.
Components of Net Periodic Benefit Cost (Income)
| | | Retirement Benefits | | Other Postretirement Benefits | | | Retirement Benefits | | Other Postretirement Benefits | |
| | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| | | Millions of dollars | | | Millions of dollars | |
| Service cost | | $ | 12.2 | | $ | 11.1 | | $ | 9.5 | | $ | 3.5 | | $ | 3.3 | | $ | 2.7 | | | $ | 14.0 | | $ | 12.2 | | $ | 11.1 | | $ | 4.6 | | $ | 3.5 | | $ | 3.3 | |
| Interest cost | | | 38.3 | | 37.4 | | 36.7 | | 10.7 | | 11.4 | | 11.4 | | | | 39.8 | | 38.3 | | 37.4 | | 11.5 | | 10.7 | | 11.4 | |
| Expected return on assets | | | (76.3 | ) | | (71.0 | ) | | (59.9 | ) | | n/a | | n/a | | n/a | | | | (75.2 | ) | | (76.3 | ) | | (71.0 | ) | | n/a | | n/a | | n/a | |
| Prior service cost amortization | | | 6.9 | | 6.6 | | 6.3 | | 0.8 | | 1.4 | | 0.9 | | | | 6.8 | | 6.9 | | 6.6 | | 1.1 | | 0.8 | | 1.4 | |
| Amortization of actuarial (gain) loss | | | - | | - | | 1.6 | | 1.2 | | 1.9 | | 1.5 | | |
| Amortization of actuarial loss | | | | 0.5 | | - | | - | | 1.7 | | 1.2 | | 1.9 | |
| Transition amount amortization | | | 0.8 | | | 0.8 | | | 0.8 | | | 0.8 | | | 0.8 | | | 0.8 | | | | 0.6 | | | 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 | | | $ | (13.5 | ) | $ | (18.1 | ) | $ | (15.1 | ) | $ | 19.7 | | $ | 17.0 | | $ | 18.8 | |
Significant Assumptions Used in Determining Net Periodic Benefit Cost (Income)
| | | Retirement Benefits | | Other Postretirement Benefits | | | Retirement Benefits | | Other Postretirement Benefits | |
| | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| Discount rate | | | 5.75 | % | | 6.00 | % | | 6.50 | % | | 5.75 | % | | 6.00 | % | | 6.50 | % | | | 5.60 | % | | 5.75 | % | | 6.00 | % | | 5.60 | % | | 5.75 | % | | 6.00 | % |
| Expected return on plan assets | | | 9.25 | % | | 9.25 | % | | 9.25 | % | | n/a | | n/a | | n/a | | | | 9.00 | % | | 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 | % | | | 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 | % | | | n/a | | | n/a | | | n/a | | | 9.00 | % | | 9.00 | % | | 9.50 | % |
| Ultimate health care cost trend rate | | | n/a | | n/a | | n/a | | 5.00 | % | | 5.00 | % | | 5.00 | % | | | n/a | | | n/a | | | n/a | | | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Year achieved | | | n/a | | n/a | | n/a | | 2011 | | 2011 | | 2011 | | | | n/a | | | n/a | | | n/a | | | 2012 | | | 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, 20052006 and 20042005 and the target allocations for 20062007 are as follows:
| | | Target Allocation | | Percentage of Plan Assets At December 31, | | | Target Allocation | | Percentage of Plan Assets At December 31, | |
Asset Category | | 2006 | | 2005 | | 2004 | | | 2007 | | 2006 | | 2005 | |
| Equity Securities | | | 70 | % | | 72 | % | | 72 | % | | | 70 | % | | 72 | % | | 72 | % |
| Debt Securities | | | 30 | % | | 28 | % | | 28 | % | | | 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, (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%9.0% 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 2006,2007, the expected rate of return also will be 9.0%.
Long-Term EquityShare-Based Compensation Plan
The SCANA Corporation 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'sCompany’s common stock, no more than one million of which may be granted in the form of restricted stock.
SFAS 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $.05 per share (net of tax) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.
Liability Awards
Through 2006, certain executives were granted a target number of performance shares on an annual basis that vest over a three-year period. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. Payout of performance share awards is determined by SCANA's performance against pre-determined measures of total shareholder return (TSR) as compared to a peer group of utilities (weighted 60%) and growth in earnings per share (as defined) (weighted 40%) over the three year plan cycle. TSR is calculated by dividing stock price change over the three-year period, plus cash dividends, by the stock price as of the beginning of the period. Payouts vary according to SCANA's ranking against the peer group and relative earnings per share projection achievement. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.
Under SFAS 123(R) compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $6.4 million were paid during the twelve months ended December 31, 2006. No such payments were made in 2005.
Fair value adjustments for performance awards resulted in a reduction to compensation expense recognized in the statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $(6.5) million for the year ended December 31, 2006, and increases to compensation expense totaling $3.6 million and $13.0 million for the years ended December 31, 2005 and 2004, respectively. Fair value adjustments resulted in a net credit to capitalized compensation cost of approximately $(0.8) million during the year ended December 31, 2006, compared to capitalized costs of approximately $0.4 million in 2005 and $1.4 million in 2004.
Equity Awards
A summary of activity related to nonqualified stock options since December 31, 2003 follows:
| | | Number of Options | | Weighted Average Exercise Price | | | 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 | | | | 1,493,685 | | $ | 27.39 | |
| Exercised | | | (751,997 | ) | | 26.28 | | | | (751,997 | ) | $ | 26.28 | |
| Forfeited | | | (11,241 | ) | | 27.52 | | | | (11,241 | ) | $ | 27.52 | |
| Outstanding-December 31, 2004 | | | 730,447 | | | 27.49 | | | | 730,447 | | $ | 27.49 | |
| Exercised | | | (297,477 | ) | | 27.40 | | | | (291,177 | ) | $ | 27.48 | |
| Forfeited | | | - | | | - | | | | - | | | - | |
| Outstanding-December 31, 2005 | | | 432,970 | | | 27.53 | | |
| Outstanding- December 31, 2005 | | | | 439,270 | | $ | 27.53 | |
| Exercised | | | | (53,330 | ) | $ | 27.52 | |
| Forfeited | | | | - | | | - | |
| Outstanding- December 31, 2006 | | | | 385,940 | | $ | 27.56 | |
No stock options have been granted since August 2002, and as of December 31, 2005, all options had vested.were fully vested in August 2005. The options expire ten years after the grant date. At December 31, 2005,2006, all outstanding options could be exercisedwere currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 6.14.9 years.
All options were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense was recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123(R), pro forma net income and earnings per share would have been unchanged from that reported for the twelve months ended December 31, 2005 and 2004.
The exercise of stock options during the period was satisfied using original issue shares of the Company’s common stock. The Company realized $1.5 million, $8.0 million and $20.5 million in cash upon the exercise of options in the twelve months ended December 31, 2006, 2005 and 2004, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $0.3 million, $1.3 million and $2.4 million were credited to additional paid in capital in these periods.
At December 31, 2004 and 2003 exercisableBeginning in 2007, the Company will satisfy the exercise of stock options totaled 388,487 at a weighted average exercise priceusing open market purchases of $27.42 and 648,392 at a weighted average exercise price of $27.19, respectively.
common stock. The Company also grants other formsestimates that 200,000 common shares will be repurchased in 2007 due to the exercise 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.options.
4. LONG-TERM DEBT
Long-term debt by type with related weighted average interest rates and maturities is as follows:
| | | | December 31, | | | | | | December 31, | |
| | Weighted-Average Interest Rate | Maturity Date | 2005 | 2004 | | Weighted-Average Interest Rate | | Maturity Date | | 2006 | | 2005 | |
| | | | Millions of dollars | | | | | | Millions of dollars | |
| Medium-Term Notes (unsecured)(a) | 6.29% | 2007-2012 | $940 | $1,040 | | | 6.40 | % | | 2007-2012 | | $ | 940 | | $ | 940 | |
| First Mortgage Bonds (secured) | 5.98% | 2009-2035 | 1,550 | 1,700 | | | 6.00 | % | | 2009-2036 | | | 1,675 | | | 1,550 | |
| First & Refunding Mortgage Bonds (secured) | 9.00% | 2006 | 131 | | | 9.00 | % | | 2006 | | | - | | | 131 | |
| GENCO Notes (secured) | 5.97% | 2011-2024 | 127 | 130 | | | 5.92 | % | | 2011-2024 | | | 123 | | | 127 | |
| Industrial and Pollution Control Bonds | 5.24% | 2012-2032 | 156 | | | 5.24 | % | | 2012-2032 | | | 156 | | | 156 | |
| Senior Debentures(b) | 7.50% | 2012-2026 | 122 | 126 | | | 7.47 | % | | 2012-2026 | | | 119 | | | 122 | |
| Fair value of interest rate swaps(c) | | | 25 | 32 | | | | | | | | | 21 | | | 25 | |
| Other | | 2006-2014 | 107 | 94 | | | | | | 2007-2014 | | | 89 | | | 107 | |
| Total debt | | | 3,158 | 3,409 | | | | | | | | | 3,123 | | | 3,158 | |
| Current maturities of long-term debt | | | (188) | (204) | | | | | | | | | (43 | ) | | (188 | ) |
| Unamortized Discount | | | (22) | (19) | | | | | | | | | (13 | ) | | (22 | ) |
| Total long-term debt, net | | | $2,948 | $3,186 | | | | | | | | $ | 3,067 | | $ | 2,948 | |
(a) | In 2005,(a) In 2006, 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(b) In 2006, includes $19.2 million of fixed rate debt hedged by variable interest rate swaps. |
(c) | In 2005, includes $24.7(c) In 2006, includes $20.7 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 20062007 through 20102011 are summarized as follows:
Year | | Amount | | | Millions of dollars | |
| | | (Millions of dollars) | | | | |
| 2006 | | $ | 188 | | |
| 2007 | | | 78 | | | $ | 43 | |
| 2008 | | | 267 | | | | 232 | |
| 2009 | | | 183 | | | | 143 | |
| 2010 | | | 50 | | | | 21 | |
| 2011 | | | | 625 | |
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 underUnder 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 fundsborrowed an aggregate $59 million from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediationback-up dam project. Such borrowings are being repaid interest-free over ten years from the initial borrowing.years. At December 31, 2006 and 2005, SCE&G had $44.3 million and $50.2 million outstanding under the agreement.agreement, respectively.
Substantially all of SCE&G's and GENCO's electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.
5. LINES OF CREDIT AND SHORT-TERM BORROWINGS
Details of lines of credit and short-term borrowings at December 31, 20052006 and 2004,2005, 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.| | | 2006 | | 2005 | |
| | | Millions of dollars | |
| Lines of credit (total and unused) | | | | | |
| Committed: | | | | | | | |
| Short-term | | $ | - | | $ | 350 | |
| Long-term | | | 1,100 | | | 650 | |
| Uncommitted (a) | | | 103 | | | 103 | |
| | | | | | | | |
| (a) SCANA or SCE&G may use $78 million of these lines of credit. | | | | | | | |
Bank loans and commercial paper outstanding (270 or fewer days) at December 31, 2006 and 2005 were as follows:
Millions of dollars | 2006 | | 2005 |
| | Amount | Weighted Average Interest Rate | | Amount | Weighted Average Interest Rate |
| SCANA | $ | - | - | | $ | 25 | 4.43% |
| SCE&G | | 238 | 5.38% | | | 196 | 4.40% |
| Fuel Company | | 124 | 5.38% | | | 107 | 4.39% |
| PSNC Energy | | 125 | 5.40% | | | 99 | 4.47% |
| Total | $ | 487 | 5.38% | | $ | 427 | 4.42% |
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.December 19, 2011. SCANA also has a five-year revolving credit facility which expires December 19, 2011.
6. COMMON EQUITY
The Company'sSCANA Corporation'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
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 20052006, approximately $51$54 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 2006, 2005 2004 and 20032004 at an annual rate per share of $1.68, $1.56 and $1.46, and $1.38, respectively.
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) | | | Unrealized Gains (Losses) on Securities | | Cash Flow Hedging Activities | | Minimum Pension Liability Adjustment | | Deferred Costs of Employee Benefit Plans | | Accumulated Other Comprehensive Income (Loss) | |
| | | Millions of dollars | | | | | | | Millions of dollars | | | |
| Balance, December 31, 2002 | | | - | | $ | 1 | | | - | | $ | 1 | | |
| Other comprehensive income | | $ | 2 | | | 3 | | | - | | | 5 | | |
| Balance, December 31, 2003 | | | 2 | | | 4 | | | - | | | 6 | | | $ | 2 | | $ | 4 | | $ | - | | $ | - | | $ | 6 | |
| Other comprehensive loss | | | (2 | ) | | (8 | ) | | - | | | (10 | ) | | | (2 | ) | | (8 | ) | | - | | | - | | | (10 | ) |
| Balance, December 31, 2004 | | | - | | | (4 | ) | | - | | | (4 | ) | | | - | | | (4 | ) | | - | | - | | (4 | ) |
| Other comprehensive income (loss) | | | - | | | 1 | | $ | (1 | ) | | - | | | | - | | | 1 | | | (1 | ) | | - | | | - | |
| Balance, December 31, 2005 | | $ | - | | $ | (3 | ) | $ | (1 | ) | $ | (4 | ) | | | - | | | (3 | ) | | (1 | ) | | - | | (4 | ) |
| Other comprehensive income (loss) | | | | - | | | (15 | ) | | 1 | | | (11 | ) | | (25 | ) |
| Balance, December 31, 2006 | | | $ | - | | $ | (18 | ) | $ | - | | $ | (11 | ) | $ | (29 | ) |
During 2006 and 2005, no unrealized gains (losses)or losses on securities were reclassified into net income. The Company recognized a loss of $27.6 million, net of tax, and a gain of $4.0 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the yearyears ended December 31, 2005. The2006 and 2005, respectively. As described in Notes 1 and 3, the Company also recorded a minimum pension liability during the year endedadopted SFAS 158 at December 31, 2005.2006 and recorded in accumulated other comprehensive income gains, losses, prior service costs and credits that have not yet been recognized through net periodic benefit cost, net of tax effects.
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 20062007 through 20102011 is $2.6$2.5 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 20052006 SCE&G had shares of preferred stock authorized and available for issuance as follows:
Par Value | Authorized | Available for Issuance | Authorized | Available for Issuance |
| $100 | 1,000,000 | - | 1,000,000 | - |
| $ 50 | 601,613 | 300,000 | 592,405 | 300,000 |
| $ 25 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 |
Preferred Stock (Not subject to purchase or sinking funds)
For each of the three years ended December 31, 20052006, SCE&G had outstanding 1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par Cumulative Preferred Stock (not subject to purchase or sinking funds).
Preferred Stock (Subject to purchase or sinking funds)
Changes in "Total“Total Preferred Stock (Subject to purchase or sinking funds)"” during 2006, 2005 2004 and 20032004 are summarized as follows:
| | Series | | | | Series | | | | | |
| | 4.50%, 4.60% (A) & 5.125% | 4.60% (B) & 6.00% | Total Shares | Millions of Dollars | | 4.50%, 4.60% (A) & 5.125% | | 4.60% (B) & 6.00% | | Total Shares | | Millions of Dollars | |
Redemption Price | $51.00 | $50.50 | | | | $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 | | | 81,034 | | 112,561 | | | 193,595 | | $ | 9.7 | |
| Shares Redeemed-$50 par value | (2,516) | (6,600) | (9,116) | (0.5) | | | (2,516 | ) | | (6,600 | ) | | (9,116 | ) | | (0.5 | ) |
| Balance at December 31, 2004 | 78,518 | 105,961 | 184,479 | 9.2 | | | 78,518 | | 105,961 | | | 184,479 | | | 9.2 | |
| Shares Redeemed-$50 par value | (1,475) | (6,600) | (8,075) | (0.4) | | | (1,475 | ) | | (6,600 | ) | | (8,075 | ) | | (0.4 | ) |
| Balance at December 31, 2005 | 77,043 | 99,361 | 176,404 | $8.8 | | | 77,043 | | 99,361 | | | 176,404 | | | 8.8 | |
| Shares Redeemed-$50 par value | | | | (2,608 | ) | | (6,600 | ) | | (9,208 | ) | | (0.5 | ) |
| Balance at December 31, 2006 | | | | 74,435 | | | 92,761 | | | 167,196 | | $ | 8.3 | |
8. INCOME TAXES
Total income tax expense (benefit) attributable to income (before cumulative effect of accounting change) for 2006, 2005 2004 and 20032004 is as follows:
| | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| | | Millions of dollars | | | Millions of dollars | |
| Current taxes: | | | | | | | | | | | | | | |
| Federal | | $ | 10.2 | | $ | (6.4 | ) | $ | 63.1 | | | $ | 93.9 | | $ | 10.2 | | $ | (6.4 | ) |
| State | | | 11.1 | | | (5.2 | ) | | 12.2 | | | | 9.8 | | | 11.1 | | | (5.2 | ) |
| Total current taxes | | | 21.3 | | $ | (11.6 | ) | $ | 75.3 | | | | 103.7 | | | 21.3 | | | (11.6 | ) |
| Deferred taxes, net: | | | | | | | | | | | | | | | | | | | | |
| Federal | | | 1.7 | | | 84.5 | | | 24.6 | | | | 11.7 | | | 1.7 | | | 84.5 | |
| State | | | (6.9 | ) | | 5.4 | | | 0.3 | | | | 5.3 | | | (6.9 | ) | | 5.4 | |
| Total deferred taxes | | | (5.2 | ) | | 89.9 | | | 24.9 | | | | 17.0 | | | (5.2 | ) | | 89.9 | |
| Investment tax credits: | | | | | | | | | | | | | | | | | | | | |
| Deferred-state | | | 5.1 | | | 10.0 | | | 5.0 | | | | 5.0 | | | 5.1 | | | 10.0 | |
| Amortization of amounts deferred-state | | | (1.9 | ) | | (2.1 | ) | | (1.8 | ) | | | (3.3 | ) | | (1.9 | ) | | (2.1 | ) |
| Amortization of amounts deferred-federal | | | (3.1 | ) | | (4.0 | ) | | (4.0 | ) | | | (3.0 | ) | | (3.1 | ) | | (4.0 | ) |
| Total investment tax credits | | | 0.1 | | | 3.9 | | | (0.8 | ) | | | (1.3 | ) | | 0.1 | | | 3.9 | |
| Synthetic fuel tax credits - federal | | | (134.2 | ) | | 40.5 | | | 35.7 | | | | - | | | (134.2 | ) | | 40.5 | |
| Total income tax expense (benefit) | | $ | (118.0 | ) | $ | 122.7 | | $ | 135.1 | | | $ | 119.4 | | $ | (118.0 | ) | $ | 122.7 | |
The difference between actual income tax expense (benefit) and that amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income (before cumulative effect of accounting change) is reconciled as follows:
| | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| | | Millions of dollars | | | Millions of dollars | |
| Income | | $319.5 | | $257.1 | | $282.0 | | | $ | 304.0 | | $ | 319.5 | | $ | 257.1 | |
| Income tax expense (benefit) | | | (118.0 | ) | | 122.7 | | | 135.1 | | | | 119.4 | | | (118.0 | ) | | 122.7 | |
| Preferred stock dividends | | | 7.3 | | | 7.3 | | | 9.1 | | | | 7.3 | | | 7.3 | | | 7.3 | |
| Total pre-tax income | | $ | 208.8 | | $ | 387.1 | | $ | 426.2 | | | $ | 430.7 | | $ | 208.8 | | $ | 387.1 | |
| | | | | | | | | | | | |
| Income taxes on above at statutory federal income tax rate | | $ | 73.1 | | $ | 135.5 | | $ | 149.2 | | | $ | 150.7 | | $ | 73.1 | | $ | 135.5 | |
| Increases (decreases) attributed to: | | | | | | | | | | | | | | | | | | | | |
| State income taxes (less federal income tax effect) | | | 4.8 | | | 5.3 | | | 10.2 | | | | 10.9 | | | 4.8 | | | 5.3 | |
| Synthetic fuel tax credits | | | (181.9 | ) | | (2.9 | ) | | (2.2 | ) | | | (33.5 | ) | | (181.9 | ) | | (2.9 | ) |
| Allowance for equity funds used during construction | | | (0.2 | ) | | (5.5 | ) | | (6.7 | ) | | | (0.2 | ) | | (0.2 | ) | | (5.5 | ) |
| Deductible dividends-Stock Purchase Savings Plan | | | (5.9 | ) | | (5.5 | ) | | (4.9 | ) | | | (6.5 | ) | | (5.9 | ) | | (5.5 | ) |
| Amortization of federal investment tax credits | | | (3.1 | ) | | (4.0 | ) | | (4.0 | ) | | | (3.0 | ) | | (3.1 | ) | | (4.0 | ) |
| Non-taxable recovery of Lake Murray Dam project carrying costs | | | (3.8 | ) | | - | | | - | | |
| Non-taxable recovery of Lake Murray back-up dam project carrying costs | | | | (2.3 | ) | | (3.8 | ) | | - | |
| Other differences, net | | | (1.0 | ) | | (0.2 | ) | | (6.5 | ) | | | 3.3 | | | (1.0 | ) | | (0.2 | ) |
| Total income tax expense (benefit) | | $ | (118.0 | ) | $ | 122.7 | | $ | 135.1 | | | $ | 119.4 | | $ | (118.0 | ) | $ | 122.7 | |
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $913.0 million at December 31, 2006 and $914.5 million at December 31, 2005 and $884.5 million at December 31, 2004 are as follows:
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Deferred tax assets: | | | | | | | | | | |
| Nondeductible reserves | | $ | 84.8 | | $ | 84.5 | | | $ | 103.8 | | $ | 84.8 | |
| Unamortized investment tax credits | | | 60.0 | | | 60.8 | | | | 58.9 | | | 60.0 | |
| Federal alternative minimum tax credit carryforward | | | 44.0 | | | 12.3 | | | | 22.1 | | | 44.0 | |
| Deferred compensation | | | 28.5 | | | 24.0 | | | | 29.0 | | | 28.5 | |
| Unbilled revenue | | | 12.6 | | | 7.0 | | | | 12.5 | | | 12.6 | |
| Other | | | 31.6 | | | 28.4 | | | | 38.6 | | | 31.6 | |
| Total deferred tax assets | | | 261.5 | | | 217.0 | | | | 264.9 | | | 261.5 | |
| | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | | | | | | | |
| Property, plant and equipment | | | 971.7 | | | 937.9 | | | | 966.8 | | | 971.7 | |
| Pension plan benefit income | | | 109.9 | | | 101.4 | | |
| Pension plan income | | | | 71.1 | | | 109.9 | |
| Deferred employee benefit plan costs | | | | 56.1 | | | - | |
| Deferred fuel costs | | | 45.1 | | | 20.3 | | | | 25.9 | | | 45.1 | |
| Other | | | 49.3 | | | 41.9 | | | | 58.0 | | | 49.3 | |
| Total deferred tax liabilities | | | 1,176.0 | | | 1,101.5 | | | | 1,177.9 | | | 1,176.0 | |
| Net deferred tax liability | | $ | 914.5 | | $ | 884.5 | | | $ | 913.0 | | $ | 914.5 | |
Previously, theThe Internal Revenue Service hadhas completed and closed examinations of the Company's consolidated federal income tax returns through tax years ending in 2000. In 2005,2004, and the Company filed amended federal incomeCompany’s tax returns through 2001 are closed 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.additional assessment. The IRS has also closed the examination ofis currently examining S. C. Coaltech No. 1 L.P.LP., a synthetic fuel partnership in which the Company has an interest, for the 20002004 tax year, resulting inyear. The Company does not anticipate that return being accepted as filed.any adjustments which might result from the examination will have a material impact on the earnings or the financial position of the Company. 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.
9. FINANCIAL INSTRUMENTS
Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 20052006 and 20042005 were as follows:
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value | | | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value | |
| | | Millions of dollars | | | Millions of dollars | |
| Long-term debt | | $ | 3,136.0 | | $ | 3,308.7 | | $ | 3,389.5 | | $ | 3,699.9 | | | $ | 3,110.0 | | $ | 3,207.9 | | $ | 3,136.0 | | $ | 3,308.7 | |
| Preferred stock (subject to purchase or sinking funds) | | | 8.2 | | | 8.2 | | | 9.2 | | | 8.5 | | | | 8.3 | | | 7.8 | | | 8.8 | | | 8.2 | |
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 which 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- downswrite-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.
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 options and swaps, which are typically offered by energy and financial institutions.
The Company recognized gains of approximately $4.0 million, $6.4 millionCompany’s regulated gas operations (SCE&G 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 hedgesEnergy) hedge gas purchasing activities using over-the-counter options and swaps and 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'soptions. SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC'sthese hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizesutilized to hedge its gas purchasing activities are recoverable through itsthe 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 include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized and unrealized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs.
The Company’s nonregulated gas operations recognize gains and losses as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period and record them, net of taxes, in cost of gas. The Company recognized gains (losses) of approximately $(27.6) million, $4.0 million and $6.4 million during the years ended December 31, 2006, 2005 and 2004, respectively. Because these gains and losses resulted from hedging activities, their effects were necessarily offset by the recording of the related hedged transactions. The Company estimates that most of the December 31, 2006 unrealized loss balance of $(17.6) million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2007 as an increase to gas cost if market prices remain at current levels. As of December 31, 2006, all of the Company's cash flow hedges settle by their terms before the end of April 2009.
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, 20052006 the estimated fair value of the Company's swaps totaled $0.1 million related to combined notional amounts of $47.4$44.2 million.
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 usesmay use interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments received or made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuanceAs permitted by SFAS 104 “Statement of First Mortgage Bonds in May 2003, the Company paid $11.9 million upon the terminationCash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions,” payments received or made are classified as a 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 agreementfinancing activity in the amountconsolidated statement 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.cash flows.
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$15 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$14.1 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. However, if such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position.
B. Environmental
South Carolina Electric & Gas Company
In March 2005 the United States 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.
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. TheAlthough the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is reviewinguncertain as to how the final rule. InstallationPhase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls is likely towill be required to comply with the rule’s Phase II mercury rule’s emission caps. ComplianceFinal compliance plans and costs to comply with the rule will be determined once the Company completes itsare still under review. Such costs will be material and are expected to be recoverable through rates.
At SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.
SCE&G has been named, along with 29 others, by the EPA as a 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, purchase of new transformers and sale of used 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. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.
SCE&G defers site assessment and cleanup costs are deferred and amortized with recovery providedrecovers them through rates.rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.7$17.9 million at December 31, 2005.2006. 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 remediation for contamination at the remaining remediation activitiessite will be completed by mid-2006,in late 2007, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005,2006, SCE&G had spent $21.5$22.3 million to remediate the Calhoun Park site and expects to spend an additional $0.3 million.$1.1 million prior to entering a monitoring and reporting stage. 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. AnySCE&G expects to recover any cost arising from the remediation of this matter is expected to be recoverablesite 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.by 2011. As of December 31, 2005,2006, SCE&G has spent $4.5$4.8 million related to these three sites, and expects to spend an additional $11.5$11.2 million. AnySCE&G expects to recover any cost arising from this matter is expected to be recoverablethe remediation of these sites 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$6.9 million, which reflects its estimated remaining liability at December 31, 2005. Amounts incurred and deferred2006. PSNC Energy expects to date, netrecover any cost allocable to PSNC Energy arising from the remediation of insurance settlements, that are not currently being recoveredthese sites 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.
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 CompanySCANA 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. While the judgment was being appealed, in May 2006 SCANA paid the plaintiff $11 million in settlement of its claims.
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 aA claim against SCANA 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.assets was settled in November 2006. 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.had been previously recorded.
OnIn 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-utilitynonutility third parties or telecommunication companies for other than the electric utilities'utility’s internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may not go to trial in 2006. The Company isbefore 2008. SCANA and SCE&G are confident of the propriety of SCE&G’s actions and intend to mount a vigorous defense. The CompanySCANA and SCE&G further believesbelieve that the resolution of these claims will not have a material adverse impact on itstheir results of operations, cash flows or financial condition.
OnIn May 17, 2004, the Company wasSCANA 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).Circuit. The plaintiff alleges the Companythat SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than the Company’sSCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes itsSCANA & SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted the Company’sSCANA’s and SCE&G’s motion to dismiss and issued an order dismissing the case onin June 29, 2005. The plaintiff has appealed.appealed to the South Carolina Supreme Court. The Company intendsSupreme Court overruled the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration. It is anticipated that this case may not go to trial before 2008. SCANA and SCE&G will continue to mount a vigorous defense and believebelieves 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 onin 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.claim against SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by South Carolina’s Circuit Court of Common Pleas for the 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.Fifth Judicial Circuit. In addition, SCE&G filed a petition with the SCPSC onin 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&G’s electric and gas service, to approve SCE&G's&G’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material loss toadverse impact on the Company.Company’s results of operations, cash flows or financial condition.
E. Other ContingencySettlement Related to Power Marketing Practices
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, 2006,18, 2007 FERC approved a settlement with SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgmentregarding the use of SCE&G’s discovery that it may have improperly utilizedelectric transmission system by its power marketing division. SCE&G identified, investigated and self-reported instances of improper utilization of 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 FERC 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 part of December 31, 2005,the settlement, SCE&G has recordedagreed that it would not retain any benefit derived from the transactions. SCE&G paid a loss accrual in the amount of approximately $0.8$9 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 modificationspenalty to the compliance plan or other non-monetary remedies. In additionU.S. Treasury. Additionally, SCE&G agreed to the disgorgement of profits, such remedies could also include penalties of upcredit an additional $1.4 million 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,benefit retail native load ratepayers and SCE&G’s institutionnon-affiliated firm transmission customers. The credit to the retail native load ratepayers was applied toward the fuel clause mechanism in January 2007. The credit to the non-affiliated firm transmission customers was refunded directly to those customers. An additional $0.4 million was credited to transmission revenue to the benefit 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&G’s rate payers. The effects of the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.settlement were accrued in 2006.
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 $15.0 million, $13.9 million and $11.8 million in 2006, 2005 and $12.4 million in 2005, 2004, and 2003, respectively. Future minimum rental payments under such leases are as follows:
| | | Millions of dollars | | | Millions of dollars | |
| 2006 | | $ | 15 | | |
| 2007 | | | 13 | | | $ | 30 | |
| 2008 | | | 12 | | | | 14 | |
| 2009 | | | 10 | | | | 10 | |
| 2010 | | | 1 | | | | 1 | |
| 2011 | | | | - | |
| Thereafter | | | 2 | | | | 2 | |
| Total | | $ | 53 | | | $ | 57 | |
At December 31, 20052006 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $6.9$5.7 million.
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 $2.4 billion, $2.2 billion and $1.6 billion in 2006, 2005 and $1.2 billion in 2005, 2004, and 2003, respectively. Future payments under such purchase commitments are as follows:
| | | Millions of dollars | | | Millions of dollars | |
| | | | | | | |
| 2006 | | $ | 1,785 | | |
| 2007 | | | 839 | | | $ | 1,623 | |
| 2008 | | | 734 | | | | 811 | |
| 2009 | | | 646 | | | | 1,221 | |
| 2010 | | | 583 | | | | 548 | |
| 2011 | | | | 499 | |
| Thereafter | | | 4,534 | | | | 3,459 | |
| Total | | $ | 9,121 | | | $ | 8,161 | |
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.
H.Asset Retirement Obligations
In accordance with SFAS 143, “Accounting for Asset Retirement Obligations,” as interpreted by FIN 47, “Accounting for Conditional Asset Retirement Obligations,” the Company recognizes a liability for the fair value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation and relates primarily to the Company’s regulated utility operations. As of December 31, 2006, the Company has recorded an ARO of approximately $92 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $199 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:
| Millions of dollars | | 2006 | | 2005 | |
| Beginning balance | | $ | 322 | | $ | 124 | |
| Liabilities incurred | | | 1 | | | - | |
| Liabilities settled | | | (2 | ) | | - | |
| Accretion expense | | | 17 | | | 7 | |
| Revisions in estimated cash flows | | | (46 | ) | | - | |
| Adoption of FIN 47 | | | - | | | 191 | |
| Ending Balance | | $ | 292 | | $ | 322 | |
Revisions in estimated cash flows relate to the estimated ARO associated with decommissioning Summer Station. The reduction is primarily related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis.
11. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are described below. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations is primarily engaged in the generation, transmission and distribution of electricity, and is regulated by the SCPSC and FERC.
Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, is engaged in the purchase and sale, primarily at retail, of natural gas. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively.
Gas Transmission is comprised of CGTC which, effective November 1, 2006, began operating as an open access, transportation-only pipeline company regulated by FERC. CGTC resulted from the merger of SCG Pipeline (previously reported in All Other) into SCPC. Prior to the merger, SCPC which is engagedpurchased, transported and sold natural gas intrastate and SCG Pipeline transported gas interstate. The results for CGTC, SCPC and SCG Pipeline appear 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.Gas Transmission reportable segment for all periods presented.
Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the Georgia Public Service Commission. Energy Marketing markets 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 onin their regulatory environment, the class of customers each serves and the marketing strategies resulting from those differences. The marketing segments differ from each other primarily based onin their respective markets and customer type.
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 | | |
2006 | | | Electric Operations | | Gas Distribution | | Gas Transmission | | Retail Gas Marketing | | Energy Marketing | | All Other | | Adjustments/ Eliminations | | Consolidated Total | |
| Customer Revenue | | $ | 1,909 | | $ | 1,168 | | $ | 237 | | $ | 664 | | $ | 799 | | $ | 70 | | $ | (70 | ) | $ | 4,777 | | | $ | 1,877 | | $ | 1,078 | | $ | 179 | | $ | 608 | | $ | 821 | | $ | 66 | | $ | (66 | ) | $ | 4,563 | |
| Intersegment Revenue | | | 4 | | 1 | | 420 | | - | | 146 | | 324 | | (895 | ) | | - | | | | 9 | | - | | 322 | | - | | | 128 | | 306 | | | (765 | ) | | - | |
| Operating Income | | | 299 | | 75 | | 21 | | n/a | | n/a | | n/a | | 41 | | 436 | | | | 456 | | 83 | | 30 | | n/a | | | n/a | | n/a | | | 34 | | | 603 | |
| Interest Expense | | | 13 | | 21 | | 6 | | 2 | | - | | 1 | | 169 | | 212 | | | | 15 | | 24 | | 7 | | 2 | | | - | | - | | | 161 | | | 209 | |
| Depreciation and Amortization | | | 450 | | 49 | | 7 | | 3 | | - | | 14 | | (13 | ) | | 510 | | | | 268 | | 54 | | 8 | | 3 | | | - | | 15 | | | (15 | ) | | 333 | |
| Income Tax Expense (Benefit) | | | 4 | | 18 | | 7 | | 14 | | (1 | ) | | 13 | | (173 | ) | | (118 | ) | | | 3 | | 16 | | 11 | | 19 | | | - | | 6 | | | 64 | | | 119 | |
| Net Income (Loss) | | | n/a | | n/a | | n/a | | 24 | | (1 | ) | | (67 | ) | | 364 | | 320 | | | | n/a | | n/a | | n/a | | 30 | | | - | | (11 | ) | | 291 | | | 310 | |
| Segment Assets | | | 5,531 | | 1,701 | | 390 | | 284 | | 128 | | 590 | | 895 | | 9,519 | | | | 5,520 | | 1,847 | | 315 | | 208 | | | 142 | | 649 | | | 1,136 | | | 9,817 | |
| Expenditures for Assets | | | 280 | | 122 | | 4 | | - | | 1 | | 19 | | (41 | ) | | 385 | | | | 304 | | 174 | | 13 | | - | | | 3 | | 35 | | | (2 | ) | | 527 | |
| Deferred Tax Assets | | | n/a | | n/a | | 6 | | 8 | | 3 | | 2 | | 7 | | 26 | | | | n/a | | n/a | | 7 | | 3 | | | 12 | | 2 | | | 10 | | | 34 | |
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 | | |
2005 | | | Electric Operations | | Gas Distribution | | Gas Transmission | | Retail Gas Marketing | | Energy Marketing | | All Other | | Adjustments/ Eliminations | | Consolidated Total | |
| Customer Revenue | | $ | 1,466 | | $ | 870 | | $ | 217 | | $ | 448 | | $ | 416 | | $ | 56 | | $ | (57 | ) | $ | 3,416 | | | $ | 1,909 | | $ | 1,168 | | $ | 237 | | $ | 664 | | $ | 799 | | $ | 70 | | $ | (70 | ) | $ | 4,777 | |
| Intersegment Revenue | | | 5 | | (1 | ) | | 303 | | - | | - | | 277 | | (584 | ) | | - | | | | 4 | | | 1 | | | 427 | | - | | | 146 | | | 317 | | | (895 | ) | | - | |
| Operating Income | | | 426 | | 77 | | 16 | | n/a | | n/a | | 1 | | 31 | | 551 | | | | 299 | | | 75 | | | 26 | | n/a | | | n/a | | | n/a | | | 36 | | | 436 | |
| Interest Expense | | | 7 | | 21 | | 5 | | 4 | | - | | 1 | | 162 | | 200 | | | | 13 | | | 21 | | | 7 | | 2 | | | - | | | - | | | 169 | | | 212 | |
| Depreciation and Amortization | | | 183 | | 47 | | 7 | | 1 | | - | | 9 | | (9 | ) | | 238 | | | | 450 | | | 49 | | | 8 | | 3 | | | - | | | 13 | | | (13 | ) | | 510 | |
| Income Tax Expense (Benefit) | | | 2 | | 19 | | 4 | | 12 | | (1 | ) | | 9 | | 90 | | 135 | | | | 4 | | | 18 | | | 8 | | 14 | | | (1 | ) | | 12 | | | (173 | ) | | (118 | ) |
| Net Income (Loss) | | | n/a | | n/a | | n/a | | 20 | | (1 | ) | | 4 | | 259 | | 282 | | | | n/a | | | n/a | | | n/a | | 24 | | | (1 | ) | | (69 | ) | | 366 | | | 320 | |
| Segment Assets | | | 5,038 | | 1,477 | | 334 | | 133 | | 53 | | 702 | | 721 | | 8,458 | | | | 5,531 | | | 1,701 | | | 427 | | 284 | | | 128 | | | 553 | | | 895 | | | 9,519 | |
| Expenditures for Assets | | | 655 | | 68 | | 18 | | - | | - | | 38 | | (99 | ) | | 680 | | | | 280 | | | 122 | | | 5 | | - | | | 1 | | | 18 | | | (41 | ) | | 385 | |
| Deferred Tax Assets | | | n/a | | n/a | | 5 | | 6 | | 2 | | 44 | | (57 | ) | | - | | | | n/a | | | n/a | | | 6 | | 8 | | | 3 | | | 2 | | | 7 | | | 26 | |
2004 | | Electric Operations | | Gas Distribution | | Gas Transmission | | Retail Gas Marketing | | Energy Marketing | | All Other | | Adjustments/ Eliminations | | Consolidated Total | |
| Customer Revenue | | $ | 1,688 | | $ | 914 | | $ | 212 | | $ | 552 | | $ | 520 | | $ | 58 | | $ | (59 | ) | $ | 3,885 | |
| Intersegment Revenue | | | 4 | | | - | | | 346 | | | - | | | 77 | | | 297 | | | (724 | ) | | - | |
| Operating Income | | | 550 | | | 67 | | | 23 | | | n/a | | | n/a | | | n/a | | | (44 | ) | | 596 | |
| Interest Expense | | | 10 | | | 21 | | | 5 | | | 3 | | | - | | | - | | | 163 | | | 202 | |
| Depreciation and Amortization | | | 208 | | | 47 | | | 8 | | | 2 | | | - | | | 11 | | | (11 | ) | | 265 | |
| Income Tax Expense (Benefit) | | | (2 | ) | | 15 | | | 6 | | | 18 | | | (1 | ) | | (9 | ) | | 96 | | | 123 | |
| Net Income (Loss) | | | n/a | | | n/a | | | n/a | | | 29 | | | (2 | ) | | (42 | ) | | 272 | | | 257 | |
| Segment Assets | | | 5,365 | | | 1,540 | | | 393 | | | 201 | | | 91 | | | 470 | | | 946 | | | 9,006 | |
| Expenditures for Assets | | | 389 | | | 86 | | | 11 | | | - | | | 3 | | | 18 | | | (6 | ) | | 501 | |
| Deferred Tax Assets | | | n/a | | | n/a | | | 5 | | | 4 | | | 3 | | | 2 | | | (4 | ) | | 10 | |
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 | | |
2006 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 | | | $ | 1,389 | | $ | 944 | | $ | 1,062 | | $ | 1,168 | | $ | 4,563 | |
| Operating income | | | 28 | | 85 | | 179 | | 144 | | 436 | | | | 185 | | 122 | | 156 | | 140 | | 603 | |
| Income before cumulative effect of accounting change | | | | 92 | | 58 | | 89 | | 65 | | 304 | |
Cumulative effect of accounting change, net of taxes (1) | | | | 6 | | - | | - | | - | | 6 | |
| Net income | | | 101 | | 44 | | 100 | | 75 | | 320 | | | | 98 | | 58 | | 89 | | 65 | | 310 | |
| Basic and diluted earnings per share | | | .89 | | .39 | | .88 | | .65 | | 2.81 | | | | .85 | | .50 | | .76 | | .57 | | 2.68 | |
2004 Millions of dollars, except per share amounts | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Annual | | |
2005 Millions of dollars, except per share amounts | | | | | | | | | | | | |
| Total operating revenues | | $ | 1,136 | | $ | 846 | | $ | 857 | | $ | 1,046 | | $ | 3,885 | | | $ | 1,266 | | $ | 891 | | $ | 1,127 | | $ | 1,493 | | $ | 4,777 | |
| Operating income | | | 194 | | 123 | | 161 | | 118 | | 596 | | | | 28 | | 85 | | 179 | | 144 | | 436 | |
| Net income | | | 101 | | 60 | | 54 | | 42 | | 257 | | | | 101 | | 44 | | 100 | | 75 | | 320 | |
| Basic and diluted earnings per share | | | .91 | | .54 | | .48 | | .37 | | 2.30 | | | | .89 | | .39 | | .88 | | .65 | | 2.81 | |
(1) The cumulative effect of accounting change is attributable to the adoption of SFAS 123(R) in the first quarter of 2006.
| | | Page |
| | | |
| Item 7. | | 9582 |
| | | | 9582 |
| | | | 9683 |
| | | | 10188 |
| | | | 10491 |
| | | | 10793 |
| | | | 10893 |
| | | | 11095 |
| | | |
| Item 7A. | | 11096 |
| | | |
| Item 8. | | 98 |
| | | | 11298 |
| | | | 11399 |
| | | | 115101 |
| | | | 116102 |
| | | | 117103 |
| | | | 118104 |
| | | |
Statements included in this discussion and analysis of OVERVIEW
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.
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 areaterritory extends into 2624 counties covering more thannearly 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 4635 counties in South Carolina and covers more than 22,00023,000 square miles.
Key earnings drivers for SCE&G over the next five years will be additions to utility rate base, drivenconsisting primarily byof 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 limitingcontrolling the growth of operation and maintenance expenses.
Electric Operations
The electric operations segment is comprised of the electric operations of SCE&G, GENCOSouth Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation, transmission and distribution of electricity in South Carolina. At December 31, 20052006 SCE&G provided electricity to approximately 610,000623,400 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. 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 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 monitormonitoring 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.
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 to retail customers in portions of South Carolina. At December 31, 20052006 this segment provided natural gas to approximately 292,000297,000 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 tois 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 beingwere not experienced in 2006 or in January or February 2007, the price of natural gas remains volatile and has resulted in short-term competitive pressure. The long-term impact of volatile gas prices and gas supply has not been determined.
Net Income
Net income was as follows:
Millions of dollars | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 258.1 | | 11.0 | % | $ | 232.5 | | 4.6 | % | $ | 222.2 | | | $ | 234.6 | | (9.1 | )% | $ | 258.1 | | | 11.0 | % | $ | 232.5 | |
| • | 2006 vs 2005 | Net income decreased primarily due to lower electric margin of $7.8 million, increased electric generation, transmission and distribution expenses of $6.9 million, increased gas distribution expenses of $1.9 million, a settlement related to power marketing practices of $8.7 million (see Note 10E of the consolidated financial statements), lower pension income and other postretirement benefits of $2.8 million, increased customer service expenses of $1.2 million and increased property taxes of $3.7 million. These increases were partially offset by higher gas margins of $10.5 million and lower incentive compensation expense of $8.6 million. |
| • | 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 Income Taxes - 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 | | | 2006 | | 2005 | | 2004 | |
| | | | | | | |
| Income Statement Impact: | | | | | | | | | | | | | | |
| (Component of) reduction in employee benefit costs | | $ | 5.6 | | $ | 4.2 | | $ | (1.0 | ) | |
| Reduction in employee benefit costs | | | $ | 2.4 | | $ | 5.6 | | $ | 4.2 | |
| Other income | | | 12.2 | | | 11.0 | | | 8.2 | | | | 12.7 | | | 12.2 | | | 11.0 | |
| 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 | ) | |
| Reduction in capital expenditures | | | | 0.7 | | | 1.6 | | | 1.2 | |
| Component of amount due to Summer Station co-owner | | | | 0.2 | | | 0.6 | | | 0.4 | |
| Total Pension Income | | $ | 20.0 | | $ | 16.8 | | $ | 6.8 | | | $ | 16.0 | | $ | 20.0 | | $ | 16.8 | |
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.Among the reasons 2006’s income was lower than 2005’s was a reduction of the assumed rate of return on assets from 9.25% to 9%. See also the discussion of pension accounting in Critical Accounting Policies and Estimates.
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 1.5%2.2% of income before income taxes in 2006, 1.5% in 2005 and 6.5% in 2004 and 8.4% in 2003.
2004. 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 Damback-up 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 2005:2006:
Declaration Date | Dividend Amount | Quarter Ended | Payment Date |
February 17, 200516, 2006 | $38.039.2 million | March 31, 20052006 | April 1, 20052006 |
May 5, 2005April 27, 2006 | $38.039.2 million | June 30, 20052006 | July 1, 20052006 |
July 27, 2005August 3, 2006 | $38.039.2 million | September 30, 20052006 | October 1, 20052006 |
November 2, 20051, 2006 | $38.021.0 million | December 31, 20052006 | January 1, 20062007 |
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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| | | | | | | |
| Operating revenues | | $ | 1,912.0 | | 13.0 | % | $ | 1,692.0 | | 15.0 | % | $ | 1,471.7 | | | $ | 1,886.6 | | | (1.3 | )% | $ | 1,912.0 | | 13.0 | % | $ | 1,692.0 | |
| Less: Fuel used in generation | | | 618.1 | | 32.4 | % | | 466.9 | | 39.7 | % | | 334.1 | | | | 615.1 | | | (0.5 | )% | | 618.1 | | 32.4 | % | | 466.9 | |
| Purchased power | | | 37.2 | | | (26.6 | )% | | 50.7 | | | (20.8 | )% | | 64.0 | | | | 27.5 | | | (26.1 | )% | | 37.2 | | (26.6 | )% | | 50.7 | |
| Margin | | $ | 1,256.7 | | | 7.0 | % | $ | 1,174.4 | | | 9.4 | % | $ | 1,073.6 | | | $ | 1,244.0 | | | (1.0 | )% | $ | 1,256.7 | | | 7.0 | % | $ | 1,174.4 | |
| • | 2006 vs 2005 | Margin decreased by $20.8 million due to unfavorable weather, by $16.0 million due to decreased off-system sales and by $6.5 million due to lower industrial sales. These decreases were offset by residential and commercial customer growth of $26.5 million and increased other electric revenue of $4.1 million. Purchased power cost decreased due to lower volumes. |
| • | 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. |
Megawatt hour (MWh) sales volumes by class, related to the electric margin above, were as follows:
Classification (in thousands) | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Residential | | | 7,634 | | 2.3 | % | | 7,460 | | 6.6 | % | | 6,998 | | | | 7,598 | | (0.5 | )% | | 7,634 | | | 2.3 | % | | 7,460 | |
| Commercial | | | 7,065 | | 2.1 | % | | 6,919 | | 4.5 | % | | 6,622 | | | | 7,268 | | 1.9 | % | | 7,135 | | | 3.1 | % | | 6,919 | |
| Industrial | | | 6,651 | | (1.8 | )% | | 6,775 | | 3.5 | % | | 6,548 | | | | 6,183 | | (6.0 | )% | | 6,581 | | | (2.9 | )% | | 6,775 | |
| Sales for resale (excluding interchange) | | | 1,487 | | (2.5 | )% | | 1,525 | | 6.1 | % | | 1,438 | | | | 1,487 | | - | | | 1,487 | | | (2.5 | )% | | 1,525 | |
| Other | | | 527 | | | 0.2 | % | | 526 | | | 5.2 | % | | 500 | | | | 531 | | 0.8 | % | | 527 | | | 0.2 | % | | 526 | |
| Total territorial | | | 23,364 | | 0.7 | % | | 23,205 | | 5.0 | % | | 22,106 | | | | 23,067 | | (1.3 | )% | | 23,364 | | | 0.7 | % | | 23,205 | |
| NMST | | | 1,794 | | | (2.8 | )% | | 1,845 | | | * | | | 425 | | |
| Negotiated Market Sales Tariff (NMST) | | | | 1,475 | | (24.9 | )% | | 1,963 | | | (6.4 | )% | | 1,845 | |
| Total | | | 25,158 | | | 0.4 | % | | 25,050 | | | 11.2 | % | | 22,531 | | | | 24,542 | | | (3.1 | )% | | 25,327 | | | 1.1 | % | | 25,050 | |
* Greater than 100%
| • | 2006 vs 2005 | Territorial sales volumes decreased by 307 MWh due to lower industrial sales volumes and by 406 MWh due to unfavorable weather. These decreases were partially offset by 408 MWh due to residential and commercial customer growth. |
| • | 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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| | | | | |
| Operating revenues | | $ | 508.8 | | 28.0 | % | $ | 397.4 | | 10.4 | % | $ | 360.1 | | | $ | 504.6 | | (0.8 | )% | $ | 508.8 | | 28.0 | % | $ | 397.4 | |
| Less: Gas purchased for resale | | | 416.6 | | | 32.8 | % | | 313.6 | | | 16.7 | % | | 268.8 | | | | 395.5 | | (5.1 | )% | | 416.6 | | 32.8 | % | | 313.6 | |
| Margin | | $ | 92.2 | | | 10.0 | % | $ | 83.8 | | | (8.2 | )% | $ | 91.3 | | | $ | 109.1 | | | 18.3 | % | $ | 92.2 | | | 10.0 | % | $ | 83.8 | |
| • | 2006 vs 2005 | Margin increased by $17.5 million due to increased retail gas base rates which became effective with the first billing cycle in November 2005 and by $4.0 million due to an SCPSC approved increase in retail gas base rates effective with the first billing cycle in November 2006. These increases were offset by $4.0 million due to lower firm margin resulting from customer conservation. |
| • | 2005 vs 2004 | Margin increased by $4.7 million due to higher firm margin and by $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. |
DTDekatherm (DT) sales volumes by class, including transportation gas, were as follows:
Classification (in thousands) | 2005 | % Change | 2004 | % Change | 2003 | 2006 | % Change | | 2005 | % Change | | 2004 |
| Residential | 12,806 | (0.9)% | 12,916 | (2.5)% | 13,243 | 10,926 | (14.7 | )% | 12,806 | (0.9 | )% | 12,916 |
| Commercial | 12,553 | 3.3% | 12,155 | (1.4)% | 12,322 | 11,984 | (4.5 | )% | 12,553 | 3.3 | % | 12,155 |
| Industrial | 15,907 | 5.4% | 15,087 | 3.9% | 14,524 | 17,879 | 12.4 | % | 15,907 | 5.4 | % | 15,087 |
| Transportation gas | 2,032 | (10.6)% | 2,272 | 6.1% | 2,141 | 2,484 | 22.2 | % | 2,032 | (10.6 | )% | 2,272 |
| Total | 43,298 | 2.0% | 42,430 | 0.5% | 42,230 | 43,273 | (0.1 | )% | 43,298 | 2.0 | % | 42,430 |
| • | 2006 vs 2005 | Residential and commercial sales volumes decreased primarily due to milder weather and conservation. Industrial and transportation sales volumes increased due to the competitive position of gas relative to alternate fuel sources. |
| • | 2005 vs 2004 | Commercial and industrial sales volumes increased primarily due to more customers buying commodity gas instead of purchasing alternativealternate 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 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| | | | | |
| Other operation and maintenance | | $ | 441.2 | | 2.4 | % | $ | 431.0 | | 7.0 | % | $ | 402.9 | | | $ | 460.7 | | | 4.4 | % | $ | 441.2 | | | 2.4 | % | $ | 431.0 | |
| Depreciation and amortization | | | 464.8 | | * | | 220.9 | | 12.6 | % | | 196.2 | | | | 285.8 | | | (38.5 | )% | | 464.8 | | | * | | | 220.9 | |
| Other taxes | | | 131.0 | | | (0.2 | )% | | 131.3 | | | 4.2 | % | | 126.0 | | | | 137.8 | | | 5.2 | % | | 131.0 | | | (0.2 | )% | | 131.3 | |
| Total | | $ | 1,037.0 | | | 32.4 | % | $ | 783.2 | | | 8.0 | % | $ | 725.1 | | | $ | 884.3 | | | (14.7 | )% | $ | 1,037.0 | | | 32.4 | % | $ | 783.2 | |
* Greater than 100%
| • | 2006 vs 2005 | Other operation and maintenance expenses increased by $11.1 million primarily due to increased electric generation, transmission and distribution expenses, by $3.1 million due to increased gas distribution expenses, by $4.6 million due to lower pension income and other postretirement benefits and by $2.0 million due to higher customer service expenses. These increases were partially offset by $13.9 million due to decreased incentive compensation expense. Depreciation and amortization expense decreased by $185.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2006 compared to 2005 (see Income Taxes -Recognition of Synthetic Fuel Tax Credits), partially offset by $6.7 million due to property additions and higher depreciation rates. Other taxes increased primarily due to higher property taxes of $6.0 million. |
| • | 2005 vs 2004 | Other operation and maintenance expenses increased primarilyby $11.5 million due to increased electric generation, major maintenancetransmission and distribution 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 (see Income Taxes -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 increased $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. |
Other Income (Expense)
Other income (expense) includes the results of certain non-utility activities. Components of other income (expense), were as follows:
Millions of dollars | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| Gain on sale of assets | | $ | 3.0 | | | 76.5 | % | $ | 1.7 | | | 21.4 | % | $ | 1.4 | |
| Other revenues | | | 60.8 | | | (62.4 | )% | | 162.4 | | | 57.5 | % | | 103.1 | |
| Other expenses | | | (45.1 | ) | | (67.9 | )% | | (140.7 | ) | | 55.1 | % | | (90.7 | ) |
| Total | | $ | 18.7 | | | (20.1 | )% | $ | 23.4 | | | 69.6 | % | $ | 13.8 | |
• | 2006 vs 2005 | Other revenues decreased $91.5 million due to lower power marketing activities, $10.8 million due to the termination of a contract to operate a steam combustion turbine at the United States Department of Energy (DOE) Savannah River Site and by $4.3 million due to lower carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project as discussed at Income Taxes - Recognition of Synthetic Fuel Tax Credits below. These decreases were partially offset by higher interest income of $8.7 million and higher third-party coal sales revenue of $4.8 million. Other expenses decreased by $90.6 million due to lower power marketing activities and $4.4 million due to the termination of the DOE’s Savannah River Site contract. These decreases were partially offset by increased charges of $8.7 million related to the settlement of the FERC power marketing matter (see Note 10 to the consolidated financial statements) and higher expenses to support third-party coal sales of $3.6 million. |
| • | 20042005 vs 20032004 | Other operation and maintenance expensesrevenues 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$42.8 million due to completion of the Jasper County Electric Generating Stationhigher power marketing activity and $11.1$10.9 million due to normal additions. carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project. Other taxesexpenses increased primarily$43.1 million due to property taxes.higher power marketing activity and $.8 million due to the charge associated with the FERC power marketing matter. (See Note 10 to the consolidated financial statements.) |
Interest Expense
Components of interest expense, excluding the debt component of AFC, were as follows:
Millions of dollars | | 2005 | | % Change | | 2004 | | % Change | | 2003 | | | 2006 | | % Change | | 2005 | | % Change | | 2004 | |
| | | | | |
| Interest on long-term debt, net | | $ | 136.3 | | (5.9 | )% | $ | 144.8 | | 3.7 | % | $ | 139.7 | | | $ | 123.9 | | | (7.1 | )% | $ | 133.3 | | (0.2 | )% | $ | 135.4 | |
| Other interest expense | | | 11.0 | | | * | | | 3.5 | | | (35.2 | )% | | 5.4 | | | | 16.1 | | | 46.4 | % | | 11.0 | | * | | | 3.5 | |
| Total | | $ | 147.3 | | | (0.7 | )% | $ | 148.3 | | | 2.2 | % | $ | 145.1 | | | $ | 140.0 | | | (3.0 | )% | $ | 144.3 | | | 3.9 | % | $ | 138.9 | |
* Greater than 100%
| • | 2006 vs 2005 | Interest on long-term debt decreased primarily due to lower interest rates and the redemption of outstanding debt in 2005. Other interest expense increased primarily due to higher principal balances and interest rates on short-term debt. |
| • | 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. |
• | 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 increased approximately $237.6 million for the year 2006 compared to 2005 and decreased approximately $269.9 million for the year 2005 compared to 2004 and increased approximately $10.2 million for the year 2004 compared to 2003.2004. Changes in income taxes are primarily due to changes in operating income, althoughand due to the recognition of $30.0 million in 2005 tax benefits of synthetic fuel tax credits ofin 2006 compared to $179.0 were also recognizedmillion in 2005 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.
Recognition of Synthetic Fuel Tax Credits
SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. Under an accounting plan approved by the Public Service Commission of South Carolina (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 back-up dam project. Under the accounting methodology approved by the SCPSC in a January 2005 order, 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 declines 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.The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2006 and 2005 are as follows:
| Millions of dollars | | 2006 | | 2005 | |
| | | | | | |
| Depreciation and amortization expense | | $ | (28.2 | ) | $ | (214.0 | ) |
| | | | | | | | |
| Income tax benefits: | | | | | | | |
| From synthetic fuel tax credits | | | 30.0 | | | 179.0 | |
| From accelerated depreciation | | | 10.8 | | | 81.8 | |
| From partnership losses | | | 7.8 | | | 28.9 | |
| Total income tax benefits | | | 48.6 | | | 289.7 | |
| | | | | | | | |
| Losses from Equity Method Investments | | | (20.4 | ) | | (75.7 | ) |
| | | | | | | | |
| Impact on Net Income | | | - | | | - | |
The 2005 amounts above reflect the recognition of previously deferred tax credits, while the 2006 amounts reflect the likelihood that credits available in 2006 will be phased down pursuant to regulations which limit the credits based on the relative commodity price of crude oil.
Depreciation on the Lake Murray back-up dam project 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 availability of 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 calculated portion of the credits would be available.
The benchmark price range for 2005, published in April 2006, was $53 to $67 per barrel, and no phase-out applied. However, SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2006 are likely to be impacted by the phase-out calculation. As such, in 2006 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 67% of credits generated will be available (phase-out of 33%). 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, there is significant uncertainty as to the continued availability of the credits in 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.
The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation, and total unrecovered cost at the end of December 31, 2007 may be significant. To the extent that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of December 31, 2006, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $69.1 million.
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 and to install equipment necessary to comply with environmental regulations, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. The Company’s future financial position and results of operations will be affected by SCE&G’s ability to obtain adequate and timely rate and other regulatory relief, if requested.
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. Ongeneration facilities. In February 10, 2006, SCE&G and Santee Cooper,the South Carolina Public Service Authority (Santee Cooper), a state-owned utility in South Carolina (joint owners of V. C. Summer Nuclear Station (Summer Station)), announced their selection of the Summer Station site as the preferred site for a new nuclear plantgeneration facilities should nuclearsuch generation be considered the best alternative in the future. Due to the significant lead time required for construction of a nuclear plant,generation facilities, the joint owners are preparing an application to the United States Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). that would cover two nuclear units. 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.generation facilities. The final decision to build a nuclear plantgeneration facilities will be influenced by several factors, including NRC licensing attainment, estimates of construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.
The Company’s current estimates of its cash requirementscapital expenditures for construction and nuclear fuel expenditures for 2006-2008,2007-2009, which are subject to continuing review and adjustment, are as follows:
Estimated Cash RequirementsCapital Expenditures
| | | 2006 | | 2007 | | 2008 | | |
Millions of dollars | | | 2007 | | 2008 | | 2009 | |
| | | Millions of dollars | | | | |
| SCE&G: | | | | | | | | | | | | | | |
| Electric Plant: | | | | | | | | | | | | | | |
| Generation (including GENCO) | | $ | 128 | | $ | 86 | | $ | 193 | | | $ | 220 | | $ | 361 | | $ | 255 | |
| Transmission | | | 50 | | | 44 | | | 46 | | | | 45 | | | 52 | | | 35 | |
| Distribution | | | 115 | | | 114 | | | 115 | | | | 151 | | | 155 | | | 153 | |
| Other | | | 18 | | | 11 | | | 14 | | | | 28 | | | 38 | | | 17 | |
| Nuclear Fuel | | | 27 | | | 25 | | | 5 | | | | 55 | | | 6 | | | 26 | |
| Gas | | | 27 | | | 26 | | | 31 | | | | 50 | | | 59 | | | 52 | |
| Common | | | 22 | | | 17 | | | 7 | | |
| Other | | | 2 | | | - | | | - | | |
| Common and Other | | | | 28 | | | 10 | | | 12 | |
| Total | | $ | 389 | | $ | 323 | | $ | 411 | | | $ | 577 | | $ | 681 | | $ | 550 | |
The Company’s contractual cash obligations as of December 31, 20052006 are summarized as follows:
Contractual Cash Obligations
(Millions of dollars) | | Total | | Less than 1 year | | 1-3 years | | 4-5 years | | After 5 years | | |
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 | | | $ | 4,559 | | $ | 493 | | $ | 499 | | $ | 377 | | $ | 3,190 | |
| Capital leases | | | 2 | | 1 | | 1 | | - | | - | | | | 2 | | 1 | | 1 | | - | | - | |
| Operating leases | | | 44 | | 13 | | 30 | | 1 | | - | | | | 49 | | 27 | | 22 | | - | | - | |
| Purchase obligations | | | 95 | | 86 | | 6 | | 3 | | - | | | | 278 | | 199 | | 76 | | 2 | | 1 | |
| Other commercial commitments | | | 672 | | | 327 | | | 285 | | | 14 | | | 46 | | | | 1,432 | | | 490 | | | 821 | | | 29 | | | 92 | |
| Total | | $ | 5,234 | | $ | 1,005 | | $ | 811 | | $ | 391 | | $ | 3,027 | | | $ | 6,320 | | $ | 1,210 | | $ | 1,419 | | $ | 408 | | $ | 3,283 | |
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 1N10H 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$7.3 million in 2005,2006, 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.
Cash outlays for 2006 (estimated)(actual) and 2005 (actual)2007 (estimated) for certain expenditures are as follows:
| | | 2006 | | 2005 | | |
| | | Millions of dollars | | |
| Property additions and construction expenditures | | $ | 368 | | $ | 331 | | |
Millions of dollars | | | | 2006 | | | 2007 | |
| Property additions and construction expenditures, net of AFC | | | $ | 412 | | $ | 522 | |
| Nuclear fuel expenditures | | | 18 | | | 18 | | | | 17 | | | 55 | |
| Investments | | | 18 | | | 18 | | | | 22 | | | 19 | |
| Total | | $ | 404 | | $ | 367 | | | $ | 451 | | $ | 596 | |
Financing Limits and Related Matters
The Company’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including the SCPSC and FERC. Financing programs currently utilized by the Company are as follows.
Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC authority to issue short-term debt. Effective February 8, 2006 the FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 7, 2008.
At December 31, 2005,2006, SCE&G and Fuel Company had available the following lines of credit and short-term borrowings outstanding:
| | | Millions of dollars | | | Millions of dollars | |
| Lines of credit (total and unused): | | | | | | |
| SCE&G and Fuel Company | | | | | | |
| Committed (expires June 2010) | | $ | 525 | | |
| Committed long-term (expires December 2011) | | | $ | 650 | |
Uncommitted | | | 78(a | ) | | | 78 | |
| Short-term borrowings outstanding: | | | | | | | | |
| Commercial paper (270 or fewer days) | | $ | 303.1 | | | $ | 362.2 | |
| Weighted average interest rate | | | 4.40 | % | | | 5.38 | % |
(a) LinesLine of credit that either SCE&G or SCANA may use.
In September 2006 SCE&G’s First and Refunding Mortgage Bond Indenture,&G discharged its bond indenture dated January 1, 1945 (Old Mortgage) and coveringwhich covered 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.
properties. SCE&G is alsoremains subject to a bond indenture dated April 1, 1993 (New Mortgage)(Mortgage) covering substantially all of its electric properties under which all of its currently outstanding First Mortgage Bonds and all of its future mortgage-backed debt (New Bonds)(Bonds) has been and will be issued. New Bonds aremay be issued under the New Mortgage onin an aggregate principal amount not exceeding the basissum of a like(1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of Class Aretired Bonds issued under the Old Mortgage which have beenand (3) cash 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. Newtrustee. Bonds will be issuable under the New Mortgage only if adjusted net earningsAdjusted 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)Bonds and New Bonds to be outstanding (New Bond(Bond Ratio). For the year ended December 31, 2005,2006, the New Bond Ratio was 6.76.6.99.
SCE&G’s Restated Articles of Incorporation (the Articles)(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, 2005,2006, the Preferred Stock Ratio was 2.12.1.99.
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, 20052006, the ten percent test would have limited total issuances of unsecured indebtedness to approximately $419.5$428.4 million. Unsecured indebtedness at December 31, 20052006, totaled approximately $246.6$357.8 million, and was comprised primarily 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.borrowings.
Financing Cash Flows
During 20052006 the Company experienced net cash outflows related to financing activities of approximately $64$38 million primarily due to the payment of dividends to SCANA.SCANA, which were partially offset by net increases in short-term borrowings.
In anticipation of the issuance of debt, the Company usesmay use interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, paymentsPayments received or made upon termination of such agreements are recorded within long-term debt on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bondsfirst mortgage bonds in May 2003,June 2006, SCE&G paid $11.9received approximately $8.8 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 startingan 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 belock. These proceeds are being amortized over the life of the related debt, to which it relates.thereby reducing its effective interest rate. As permitted by SFAS 104 “Statement of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions,” these proceeds have been classified as a financing activity in the consolidated statement of cash flows.
For additional information on significant financing transactions, see Note 4 to the Company’s consolidated financial statements.
Capital Expenditures
For the three years ended December 31, 2005,2006, the Company’s capital expenditures for environmental control totaled $199.2$160.2 million. These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $28.1 million, $25.2 million, and $21.3 million during 2006, 2005 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$154.6 million for 20062007 and $314.1$494.6 million for the four-year period 20072008 through 2010.2011. 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 United States 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 installingbelieves that installation of additional air quality controls will be needed to meet the CAIR requirements. InstallationThe Company is reviewing the final rule. Compliance plans and operation and maintenance costs are currently being determined.cost to comply with the rule will be determined once the Company completes its review. Such costs are likelywill 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. TheAlthough the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is negotiating withuncertain as to how the South Carolina Department of Health and Environmental Control the terms of the state compliance proposals. InstallationPhase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls is likely towill be required to comply with the rule’s Phase II mercury rule’s emission caps. ComplianceFinal compliance plans and costs to comply with the rule will be determined once the Company completes its review and assessments.are still under review. Such costs are likely towill be material and are expected to be recoverable through rates.
The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the DOJUnited States Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the CAA.Clean Air Act (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 Companyindustry is not binding as precedent and the one favorable to the Companyindustry 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,the Company, 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 expectThe Company expects to incur capital expenditures totaling approximately $331$450 million over the 2006-20092007-2010 period to install this new equipment. SCE&G and GENCO expectThe Company expects to have increased operation and maintenance costs of approximately $4 million in 20092010 and $27 million in 20102011 and subsequent years. To meet compliance requirements for the years 20112012 through 2015,2016, the Company anticipates additional capital expenditures totaling approximately $564$480 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(Nuclear Waste Act”)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 imposesimposed 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 $9 million settlement from DOE which requires the payment by DOE of $9 million to the plaintiffs.DOE. The payment is to reimbursereimbursed the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. SCE&G will recordrecorded its portion ($6 million) of the settlement as a reduction to its fuel costs. As a result, most of the credit will bewas 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.
SCE&G has been named, along with 29 others, by the 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, purchase of new transformers and sale of used 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. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates. 94
SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.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$17.9 million and $10.5$17.7 million at December 31, 20052006 and 2004,2005, respectively. The deferral includes the estimated costs associated with the following matters: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 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 operationanticipates that remediation for contamination at the site from 1967 to 1984. During that time,will be completed in late 2007, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2006, 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$22.3 million to date. SCE&G’s records indicated that only minimal quantitiesremediate the Calhoun Park site, and expects to spend an additional $1.1 million. In addition, the National Park Service of used transformers were shipped by itthe Department of the Interior made an initial demand 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 atfor payment of $9.1 million for certain costs and damages relating to 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. Anysite. SCE&G expects to recover any cost arising from the remediation of this matter is expected to be recoverablesite 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 2011. As of December 31, 2006, SCE&G has spent $4.8 million related to these three sites, and expects to spend an additional $11.2 million. SCE&G expects to recover any cost arising from the remediation of this site through rates.
See earlier discussion of increases in retail electric and gas base rates during 20052006 in Liquidity and Capital Resources.
In February 2005, theThe 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.
Following are descriptions of the Company’s accounting policies and estimates 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 or financial position of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. It is not expected that cash flows 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, 2005,2006, the Company’s net investments in fossil/hydro and nuclear generation assets were $2.3 billion and $552$506 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 customercustomers 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, 20052006 and 2004,2005, accounts receivable included unbilled revenues of $99.7$91.7 million and $80.6$99.7 million, respectively, compared to total revenues for 2005each of the years 2006 and 20042005 of $2.4 billion and $2.1 billion, respectively.billion.
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 asand 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’sSCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals approximately $357$451.0 million, stated in 1999 dollars. This estimate is2006 dollars, 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.Summer Station. The cost estimate is based on a decommissioning methodology acceptable to the NRC under whichassumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permitswould permit release for unrestricted use.
Under the Company’sSCE&G’s method of funding decommissioning costs, fundsamounts collected through rates are invested in insurance policies on the lives of certain Company and affiliate personnel. Amounts for decommissioningSCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferredexpenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies held by SCE&G to an external trust fund.the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
Accounting for Pensions and Other Postretirement Benefits
SCANA follows SFAS 87, “Employers’“Employers’ Accounting for Pensions,” as amended by SFAS 158, in accounting for the cost of its defined benefit pension plan. SCANA’s plan is fullyadequately 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$15.8 million recorded in 20052006 reflects the use of a 5.75%5.60% discount rate and an assumed 9.25%9.00% long-term rate of return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.5%5.35% in 20052006 would have increaseddecreased the Company’s share of SCANA’s pension income approximately $0.5by $0.9 million. Had the assumed long-term rate of return on assets been 9.0%8.75%, the Company’s share of SCANA’s pension income for 20052006 would have been reduced by approximately $2.0$2.1 million.
In determining the appropriate discount rate for 2005, SCANA considered the market indices of high-quality long-term fixed income securities andFor 2006, SCANA selected the discount rate of 5.75% as being within5.60% which was derived using a reasonable range of interest rates for obligations rated Aa by Moody’s as of January 1, 2005.cash flow matching technique. For 2006,2007, the discount rate to be used will be 5.6%5.85%, which was derived using athat same cash flow matching technique which SCANA believes is preferable.technique. 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’ 20052006 review of the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 9.8%9.3%, 11.6%11.0%, 11.6%11.2% and 12.3%12.7%, respectively, all of which have been in excess of related broad indices. The 20052006 expected long-term rate of return of 9.25%9.0% was based on a target asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2006,2007, the expected rate of return will be 9.0%9.00%.
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,” as amended by SFAS 158, in accounting for the cost of its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 5.75%5.60% and recorded a net SFAS 106 cost of $12.3$16.8 million for 2005.2006. Had the selected discount rate been 5.50%5.35%, the expense for 20052006 would have been approximately $0.2$0.4 million higher. The Company also adopted the balance sheet recognition provisions of SFAS 158 effective December 31, 2006, as more fully described in Note 3 to the consolidated financial statements. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.
The Company also adopted the balance sheet recognition provisions of SFAS 158 effective December 31, 2006, as more fully described in Note 3 to the consolidated financial statements. Asset Retirement Obligations
SFAS 143,“Accounting for Asset Retirement Obligations,” together with FIN 47, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates to the Company’s regulated utility operations, adoption of SFAS 143 and FIN 47 hadhave no impact on results of operations. As of December 31, 2005,2006, the Company has recorded an ARO of approximately $132$93 million for nuclear plant decommissioning (as discussed above) and an ARO of approximately $178$186 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines, which waspipelines. The ARO for nuclear plant decommissioning reflects a reduction of $46 million from the corresponding ARO recorded under FIN 47.as of December 31, 2005. The reduction is primarily related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis. 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,time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s regulated utilities remains in place.
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,FIN 46(R), “Consolidation of Variable Interest Entities.” SCE&G does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture 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.
All financial instruments held by SCE&G described below are held for purposes other than trading.
Interest rate risk-TheThe tables below provide information aboutsummarize 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 | Expected Maturity Date |
December 31, 2005 Millions of dollars | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | Fair Value | |
| Liabilities | | | | | | |
December 31, 2006 Millions of dollars | | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total | Fair Value |
| Long-Term Debt: | | | | | | | | | |
| Fixed Rate ($) | 169.9 | 39.2 | 139.2 | 39.2 | 1,714.4 | 2,141.1 | 2,051.3 | 3.7 | 103.7 | 10.4 | 164.9 | 1,667.9 | 1,954.3 | 2,001.2 |
| Average Interest Rate (%) | 8.51 | 6.86 | 6.33 | 6.86 | 5.88 | 6.17 | | 7.78 | 6.18 | 6.31 | 6.70 | 5.83 | 5.93 | |
| | Expected Maturity Date | Expected Maturity Date |
December 31, 2004 Millions of dollars | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | Fair Value | |
| Liabilities | | | | | | |
December 31, 2005 Millions of dollars | | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | Fair Value |
| Long-Term Debt: | | | | | | | | | |
| Fixed Rate ($) | 189.2 | 169.9 | 39.2 | 39.2 | 139.2 | 1,718.2 | 2,294.9 | 2,285.7 | 169.9 | 39.2 | 139.2 | 39.2 | 1,714.4 | 2,141.1 | 2,051.3 |
| Average Interest Rate (%) | 7.37 | 8.51 | 6.86 | 6.86 | 6.33 | 6.02 | 6.36 | | 8.51 | 6.86 | 6.33 | 6.86 | 5.88 | 6.17 | |
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 approximatelylong-term debt of $80 million at December 31, 2006 and $97 million and $81 million in long-term debt as ofat December 31, 2005, and 2004, respectively, which amounts do not have a stated interest rate associated with them.
Commodity Price Risk
In December 2005The following table summarizes 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 fairCompany’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value of this treasury lock agreement was a loss of $3.8 million.represents quoted market prices.
| Expected Maturity: | | | |
| | | | |
| | Futures Contracts | |
| 2007 | Long | Short | |
| | | | |
| Settlement Price (a) | 6.82 | 6.61 | |
| Contract Amount (b) | 28.6 | 2.9 | |
| Fair Value (b) | 21.8 | 2.0 | |
| | | | |
| 2008 | | | |
| | | | |
| Settlement Price (a) | 8.46 | - | |
| Contract Amount (b) | 5.2 | - | |
| Fair Value (b) | 4.9 | - | |
| | | | |
| (a) Weighted average, in dollars | | |
| (b) Millions of dollars | | | |
| | Expected Maturity |
| Commodity Swaps | 2007 | 2008 |
| | | |
| Commodity Swaps: | | |
| Pay fixed/receive variable (b) | 53.7 | 32.6 |
| Average pay rate (a) | 8.8558 | 8.7337 |
| Average received rate (a) | 7.1309 | 8.3193 |
| Fair value (b) | 43.3 | 31.1 |
| | | |
| (a) Weighted average, in dollars | | |
| (b) Millions of dollars | | |
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 9 to the consolidated financial statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheetsconsolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the “Company”) as of December 31, 20052006 and 2004,2005, and the related Consolidated Statementsconsolidated statements of Income, Changesincome, changes in Common Equitycommon equity, and of Cash Flowscash flows for each of the three years in the period ended December 31, 2005.2006. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’sCompany'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.
As discussed in Note 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006.
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, 20052006 and 20042005 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005,2006, 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, 2006February 28, 2007
SOUTH CAROLINA ELECTRIC & GAS COMPANY
December 31, (Millions of dollars) | | 2006 | | 2005 | |
Assets | | | | | |
| Utility Plant In Service: | | $ | 7,876 | | $ | 7,687 | |
| Accumulated Depreciation and Amortization | | | (2,483 | ) | | (2,295 | ) |
| | | | 5,393 | | | 5,392 | |
| Construction Work in Progress | | | 316 | | | 160 | |
| Nuclear Fuel, Net of Accumulated Amortization | | | 39 | | | 28 | |
| Utility Plant, Net | | | 5,748 | | | 5,580 | |
| Nonutility Property and Investments: | | | | | | | |
| Nonutility property, net of accumulated depreciation | | | 31 | | | 28 | |
| Assets held in trust, net-nuclear decommissioning | | | 56 | | | 52 | |
| Other investments | | | 25 | | | 28 | |
| Nonutility Property and Investments, Net | | | 112 | | | 108 | |
| Current Assets: | | | | | | | |
| Cash and cash equivalents | | | 24 | | | 19 | |
| Receivables, net of allowance for uncollectible accounts of $5 and $2 | | | 311 | | | 366 | |
| Receivables-affiliated companies | | | 41 | | | 32 | |
| Inventories (at average cost): | | | | | | | |
| Fuel | | | 147 | | | 62 | |
| Materials and supplies | | | 85 | | | 72 | |
| Emission allowances | | | 22 | | | 54 | |
| Prepayments and other | | | 20 | | | 12 | |
| Deferred income taxes | | | 19 | | | 22 | |
| Total Current Assets | | | 669 | | | 639 | |
| Deferred Debits: | | | | | | | |
| Pension asset, net | | | 200 | | | 303 | |
| Due from affiliates-pension and benefits | | | 41 | | | 31 | |
| Emission allowances | | | 27 | | | - | |
| Regulatory assets | | | 702 | | | 584 | |
| Other | | | 127 | | | 121 | |
| Total Deferred Debits | | | 1,097 | | | 1,039 | |
| Total | | $ | 7,626 | | $ | 7,366 | |
December 31, (Millions of dollars) | | 2006 | | 2005 | |
Capitalization and Liabilities | | | | | |
| Shareholders’ Investment: | | | | | |
| Common equity | | $ | 2,457 | | $ | 2,362 | |
| Preferred stock (Not subject to purchase or sinking funds) | | | 106 | | | 106 | |
| Total Shareholders’ Investment | | | 2,563 | | | 2,468 | |
| Preferred Stock, net (Subject to purchase or sinking funds) | | | 8 | | | 8 | |
| Long-Term Debt, net | | | 2,008 | | | 1,856 | |
| Total Capitalization | | | 4,579 | | | 4,332 | |
| Minority Interest | | | 86 | | | 82 | |
| Current Liabilities: | | | | | | | |
| Short-term borrowings | | | 362 | | | 303 | |
| Current portion of long-term debt | | | 14 | | | 183 | |
| Accounts payable | | | 155 | | | 84 | |
| Accounts payable—affiliated companies | | | 147 | | | 142 | |
| Customer deposits and customer prepayments | | | 40 | | | 35 | |
| Taxes accrued | | | 112 | | | 140 | |
| Interest accrued | | | 33 | | | 35 | |
| Dividends declared | | | 23 | | | 40 | |
| Other | | | 63 | | | 38 | |
| Total Current Liabilities | | | 949 | | | 1,000 | |
| Deferred Credits: | | | | | | | |
| Deferred income taxes, net | | | 807 | | | 801 | |
| Deferred investment tax credits | | | 118 | | | 119 | |
| Asset retirement obligations | | | 279 | | | 309 | |
| Postretirement benefits | | | 194 | | | 148 | |
| Due to affiliates-pension and benefits | | | 6 | | | 12 | |
| Regulatory liabilities | | | 541 | | | 488 | |
| Other | | | 67 | | | 75 | |
| Total Deferred Credits | | | 2,012 | | | 1,952 | |
| Commitments and Contingencies (Note 10) | | | - | | | - | |
| Total | | $ | 7,626 | | $ | 7,366 | |
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
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 | |
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 | |
For the Years Ended December 31, (Millions of dollars) | | 2006 | | 2005 | | 2004 | |
| Operating Revenues: | | | | | | | |
| Electric | | $ | 1,886 | | $ | 1,912 | | $ | 1,692 | |
| Gas | | | 505 | | | 509 | | | 397 | |
| Total Operating Revenues | | | 2,391 | | | 2,421 | | | 2,089 | |
| Operating Expenses: | | | | | | | | | | |
| Fuel used in electric generation | | | 615 | | | 618 | | | 467 | |
| Purchased power | | | 27 | | | 37 | | | 51 | |
| Gas purchased for resale | | | 396 | | | 417 | | | 313 | |
| Other operation and maintenance | | | 461 | | | 441 | | | 431 | |
| Depreciation and amortization | | | 286 | | | 465 | | | 221 | |
| Other taxes | | | 138 | | | 131 | | | 131 | |
| Total Operating Expenses | | | 1,923 | | | 2,109 | | | 1,614 | |
| Operating Income | | | 468 | | | 312 | | | 475 | |
| Other Income (Expense): | | | | | | | | | | |
| Other revenues | | | 61 | | | 163 | | | 103 | |
| Other expenses | | | (45 | ) | | (140 | ) | | (90 | ) |
| Gains on sale of investments and assets | | | 3 | | | - | | | 1 | |
| Allowance for equity funds used during construction | | | - | | | - | | | 14 | |
| Interest charges, net of allowance for borrowed funds used during construction of $8, $3 and $9 | | | (140 | ) | | (144 | ) | | (139 | ) |
| Total Other Expense | | | (121 | ) | | (121 | ) | | (111 | ) |
| | | | | | | | | | | |
| Income Before Income Taxes (Benefit), Losses from Equity Method Investments, Minority | | | | | | | | | | |
| Interest, Cumulative Effect of Accounting Change and Preferred Stock Dividends | | | 347 | | | 191 | | | 364 | |
| Income Tax Expense (Benefit) | | | 88 | | | (150 | ) | | 120 | |
| | | | | | | | | | | |
| Income Before Losses from Equity Method Investments, Minority Interest, | | | | | | | | | | |
| Cumulative Effect of Accounting Change and Preferred Stock Dividends | | | 259 | | | 341 | | | 244 | |
| Losses from Equity Method Investments | | | (22 | ) | | (77 | ) | | (2 | ) |
| Minority Interest | | | 7 | | | 6 | | | 10 | |
| Cumulative Effect of Accounting Change, net of taxes | | | 4 | | | - | | | - | |
| | | | | | | | | | | |
| Net Income | | | 234 | | | 258 | | | 232 | |
| Preferred Stock Cash Dividends | | | 7 | | | 7 | | | 7 | |
| Earnings Available for Common Shareholder | | $ | 227 | | $ | 251 | | $ | 225 | |
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
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.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
For the Years Ended December 31, (Millions of dollars) | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| Cash Flows From Operating Activities: | | | | | | | | | | | | | | |
| Net income | | $ | 258 | | $ | 232 | | $ | 220 | | | $ | 234 | | $ | 258 | | $ | 232 | |
| Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities: | | | | | | | | | | | |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | | | | | | | | |
| Cumulative effect of accounting change, net of taxes | | | | (4 | ) | | - | | | - | |
| Losses from equity method investments | | | 77 | | | 2 | | | 1 | | | | 22 | | 77 | | | 2 | |
| Minority interest | | | 6 | | | 10 | | | 8 | | | | 7 | | 6 | | | 10 | |
| Depreciation and amortization | | | 465 | | | 221 | | | 196 | | | | 286 | | 465 | | | 221 | |
| Amortization of nuclear fuel | | | 18 | | | 22 | | | 21 | | | | 17 | | 18 | | | 22 | |
| Gain on sale of assets | | | (1 | ) | | (1 | ) | | (1 | ) | | | (3) | | (1 | ) | | (1 | ) |
| Allowance for equity funds used during construction | | | - | | | (14 | ) | | (18 | ) | | | - | | - | | | (14 | ) |
| Carrying cost recovery | | | (11 | ) | | - | | | - | | | | (7 | ) | | (11 | ) | | - | |
| Cash provided (used) by changes in certain assets and liabilities: | | | | | | | | | | | | | | | | | | | |
| Receivables, net | | | (87 | ) | | (19 | ) | | (35 | ) | | | 49 | | (87 | ) | | (19 | ) |
| Inventories | | | (119 | ) | | (44 | ) | | - | | | | (146 | ) | | (119 | ) | | (44 | ) |
| Prepayments | | | 18 | | | (10 | ) | | 4 | | | | (8) | | 18 | | | (10 | ) |
| Pension asset | | | (17 | ) | | (14 | ) | | (5 | ) | | | (13 | ) | | (17 | ) | | (14 | ) |
| Other regulatory assets | | | (30 | ) | | (17 | ) | | 4 | | |
| Regulatory assets | | | | (10 | ) | | (30 | ) | | (17 | ) |
| Deferred income taxes, net | | | 19 | | | 44 | | | 51 | | | | 14 | | 19 | | | 44 | |
| Other regulatory liabilities | | | (165 | ) | | 42 | | | 46 | | | | 9 | | (165 | ) | | 42 | |
| Postretirement benefits | | | 6 | | | 7 | | | 4 | | | | (3 | ) | | 6 | | | 7 | |
| Accounts payable | | | 6 | | | (17 | ) | | 3 | | | | (16 | ) | | 6 | | | (17 | ) |
| Taxes accrued | | | (12 | ) | | 34 | | | 4 | | | | (28 | ) | | (12 | ) | | 34 | |
| Interest accrued | | | - | | | (4 | ) | | 8 | | | | (2 | ) | | - | | | (4 | ) |
| Changes in fuel adjustment clauses | | | (32 | ) | | 8 | | | 11 | | | | 32 | | (32 | ) | | 8 | |
| Changes in other assets | | | (13 | ) | | 13 | | | (5 | ) | | | 19 | | (13 | ) | | 13 | |
| Changes in other liabilities | | | 24 | | | 36 | | | 42 | | | | 25 | | | 24 | | | 36 | |
| Net Cash Provided From Operating Activities | | | 410 | | | 531 | | | 559 | | | | 474 | | | 410 | | | 531 | |
| Cash Flows From Investing Activities: | | | | | | | | | | | | | | | | | | | |
| Utility property additions and construction expenditures | | | (330 | ) | | (434 | ) | | (589 | ) | | | (409 | ) | | (330 | ) | | (434 | ) |
| Nonutility property additions | | | 1 | | | (5 | ) | | - | | | | (3 | ) | | (1 | ) | | (5 | ) |
| Proceeds from sales of assets | | | 2 | | | 2 | | | 2 | | | | 3 | | 2 | | | 2 | |
| Investments | | | (18 | ) | | (20 | ) | | (21 | ) | | | (22 | ) | | (18 | ) | | (20 | ) |
| Net Cash Used For Investing Activities | | | (347 | ) | | (457 | ) | | (608 | ) | | | (431 | ) | | (347 | ) | | (457 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | | | | | | | | | | |
| Proceeds from issuance of debt | | | 121 | | | 136 | | | 779 | | | | 132 | | 121 | | | 136 | |
| Contribution from parent | | | 95 | | | 38 | | | 39 | | | | 9 | | 95 | | | 38 | |
| Repayment of debt | | | (264 | ) | | (110 | ) | | (441 | ) | | | (151 | ) | | (264 | ) | | (110 | ) |
| Redemption of preferred stock | | | (1 | ) | | - | | | (50 | ) | | | - | | (1 | ) | | - | |
| Dividends on equity securities | | | (158 | ) | | (158 | ) | | (159 | ) | |
| Dividends | | | | (162 | ) | | (158 | ) | | (158 | ) |
| Distribution to parent | | | - | | | (29 | ) | | - | | | | - | | - | | | (29 | ) |
| Short-term borrowings - affiliate, net | | | (7 | ) | | - | | | (48 | ) | | | 75 | | (7 | ) | | - | |
| Short-term borrowings, net | | | 150 | | | 13 | | | (38 | ) | | | 59 | | | 150 | | | 13 | |
| Net Cash Provided From (Used For) Financing Activities | | | (64 | ) | | (110 | ) | | 82 | | |
| Net Cash Used For Financing Activities | | | | (38 | ) | | (64 | ) | | (110 | ) |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (1 | ) | | (36 | ) | | 33 | | | | 5 | | (1 | ) | | (36 | ) |
| Cash and Cash Equivalents, January 1 | | | 20 | | | 56 | | | 23 | | | | 19 | | | 20 | | | 56 | |
| Cash and Cash Equivalents, December 31 | | $ | 19 | | $ | 20 | | $ | 56 | | | $ | 24 | | $ | 19 | | $ | 20 | |
| Supplemental Cash Flow Information: | | | | | | | | | | | | | | | | | | | |
| Cash paid for - Interest (net of capitalized interest of $3, $9 and $11) | | $ | 140 | | $ | 144 | | $ | 125 | | |
| Cash paid for - Interest (net of capitalized interest of $8, $3 and $9) | | | $ | 122 | | $ | 140 | | $ | 144 | |
| - Income taxes | | | 26 | | | 22 | | | 41 | | | | 93 | | 26 | | | 22 | |
| Noncash Investing and Financing Activities: | | | | | | | | | | | | | | | | | | | |
| Accrued construction expenditures | | | 29 | | | 38 | | | 30 | | | | 43 | | 29 | | | 38 | |
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
| | | | | | | | |
| | | | 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 |
| | | | | | | | | | | Accumulated | | | |
| | | | | | | Other | | | | Other | | Total | |
| | | Common Stock (a) | | Paid In | | Retained | | Comprehensive | | Common | |
| | | Shares | | Amount | | Capital | | Earnings | | Income (Loss) | | Equity | |
| | | (Millions) | |
| | | | | | | | | | | | | | |
| Balance at December 31, 2003 | | | 40 | | $ | 571 | | $ | 636 | | $ | 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 | | | 571 | | | 674 | | | 919 | | | | | | 2,164 | |
| Capital Contributions From Parent | | | | | | | | | 95 | | | | | | | | | 95 | |
| Earnings Available for Common Shareholder | | | | | | | | | | | | 251 | | | | | | 251 | |
| Cash Dividends Declared | | | | | | | | | | | | (148 | ) | | | | | (148 | ) |
| Balance at December 31, 2005 | | | 40 | | | 571 | | | 769 | | | 1,022 | | | | | | 2,362 | |
| Capital Contributions From Parent | | | | | | | | | 9 | | | | | | | | | 9 | |
| Earnings Available for Common Shareholder | | | | | | | | | | | | 227 | | | | | | 227 | |
| Deferred Cost of Employee Benefit Plans, | | | | | | | | | | | | | | | | | | | |
| net of taxes $(4) | | | | | | | | | | | | | | $ | (7 | ) | | (7 | ) |
| Cash Dividends Declared | | | | | | | | | | | | (134 | ) | | | | | (134 | ) |
| Balance at December 31, 2006 | | | 40 | | $ | 571 | | $ | 778 | | $ | 1,115 | | $ | (7 | ) | $ | 2,457 | |
(a) $4.50 par value, authorized 50 million shares
The Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other comprehensive income gains, losses, prior service costs and credits that have not yet been recognized through net periodic benefit cost, net of tax effects.
See Notes to Consolidated Financial Statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
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 engagedengages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts of SCE&G, South Carolina Fuel Company, Inc. (Fuel Company), and South Carolina Generating Company, Inc,Inc. (GENCO) and SCE&G Trust I.. Intercompany balances and transactions between SCE&G, Fuel Company GENCO and SCE&G Trust IGENCO 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 agreement and related operating agreement. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $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 tothe regulatory assets and regulatory liabilities summarized as 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 | ) |
| | | December 31, | |
| Millions of dollars | | 2006 | | 2005 | |
Regulatory Assets: | | | |
| Accumulated deferred income taxes | | $ | 169 | | $ | 170 | |
| Under-collections-electric fuel and gas cost adjustment clauses | | | 49 | | | 56 | |
| Purchased power costs | | | 9 | | | 17 | |
| Environmental remediation costs | | | 18 | | | 18 | |
| Asset retirement obligations and related funding | | | 254 | | | 240 | |
| Franchise agreements | | | 55 | | | 56 | |
| Regional transmission organization costs | | | 8 | | | 11 | |
| Deferred employee benefit plan costs | | | 128 | | | - | |
| Other | | | 12 | | | 16 | |
| Total Regulatory Assets | | $ | 702 | | $ | 584 | |
| | | December 31, | |
| Millions of dollars | | 2006 | | 2005 | |
Regulatory Liabilities: | | | | | | | |
| Accumulated deferred income taxes | | $ | 34 | | $ | 36 | |
| Other asset removal costs | | | 438 | | | 394 | |
| Storm damage reserve | | | 44 | | | 38 | |
| Planned major maintenance | | | 6 | | | 9 | |
| Other | | | 19 | | | 11 | |
| Total Regulatory Liabilities | | $ | 541 | | $ | 488 | |
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-electricUnder-collections-electric fuel and gas cost adjustment clauses, net, represent amounts under-(over-) collectedunder-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings. Included in these amounts are regulatory assets or liabilities arising from the natural gas hedging programs of the Company’s regulated operations. See Note 1F.Notes 1E and 1L.
Deferred purchasedPurchased power costs-represents costs that wererepresent costs 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 environmentalEnvironmental 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$17.9 million remain.remain to be recovered.
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, “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. TheseSCE&G is amortizing these amounts are not earning a return, but are being amortized through cost of service rates and are expected to be amortized over approximately 1520 years.
Deferred regionalRegional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. Effective January 2005, the SCPSC approved the amortization of these amounts through cost of service rates over approximately five years.
Deferred employee benefit plan costs represent amountsof pension and other postretirement benefit costs which were accrued as liabilities under provisions of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” but which are expected to be recovered through utility rates (see Note 3).
Other asset removal costs represent net collections through depreciation rates of estimated costs to be incurred for the removal of assets in the future.
The storm damage reserve represents an SCPSC-approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. During the years ended December 31, 2006 and 2005, no significant amounts were drawn from this reserve account.
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 incurred, as approved through specific SCPSC orders. SCE&G is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle and are a component of cost of service and do not receive special rate consideration.
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.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 SCPSCstate 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 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 ofjointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company’s portion of Summer Station was approximately $1.0 billion as of December 31, 20052006 and 20042005 (including amounts related to ARO). Accumulated depreciation associated with the Company’s share of Summer Station was $478.7$496.8 million and $463.7$478.7 million as of December 31, 20052006 and 2004,2005, respectively (including amounts related to ARO). The Company’s share of the direct expenses associated with operating Summer Station is included in “Otherother operation and maintenance”maintenance expenses and totaled $77.7 million, $76.3 million $74.5 million and $74.7$74.5 million for the years ended December 31, 2006, 2005 and 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 collectcollecting $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2005,2006, the Company incurred $4.9$7.2 million for turbine maintenance. The remaining $3.6$1.3 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 CompanySCE&G accrued $0.8$1.0 million per month from January 2004July 2005 through June 2005December 2006 for its portion of the outage in April 2005October 2006 and is accruing approximately $1.0$1.1 million per month for its portion of the outage scheduled for October 2006.the spring of 2008. Total costs for the 2005 outage in 2006 were approximately $22.3$25.5 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$17.0 million. As of December 31, 20052006 and 2004,2005, the Company had accrued $0.2 million and $5.7 million, and $9.9 million, respectively.
E.D. Allowance for Funds Used During Construction (AFC)
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 3.2%5.0%, 3.2% and 6.7% for 2006, 2005 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. InterestSCE&G capitalizes interest on nuclear fuel in process is capitalized at the actual interest amount incurred.
F.E. Revenue Recognition
Revenues are recordedThe Company records revenues during the accounting period in which it provides services are provided to customers and includeincludes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $99.7$91.7 million and $80.6$99.7 million as of December 31, 2006 and 2005, and 2004, respectively.
Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel costThis 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$28.9 million and $6.0$44.1 million at December 31, 20052006 and 2004,2005, 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, 20052006 and 20042005, the Company had undercollected (overcollected) $11.8$20.3 million and $(7.8)$11.8 million, respectively, which amounts are also included in other regulatory assets or liabilities.assets.
The Company’s gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment which minimizes fluctuations in gas revenues due to abnormal weather conditions.
G.F. Depreciation and Amortization
ProvisionsThe Company records 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%3.15%, 3.16% and 2.97% for 2006, 2005 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.
The Company records nuclear fuel amortization using the units-of-production method. 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.retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the Department of Energy (DOE) under a contract for disposal of spent nuclear fuel.
H.G. Nuclear Decommissioning
The Company’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $357.3$451.0 million, stated in 19992006 dollars, based on a decommissioning study completed in 2000.2006. 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 whichassumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permitswould permit release for unrestricted use.
Under the Company’s method of funding decommissioning costs, fundsamounts collected through rates ($3.2 million pre-tax in each of 2006, 2005 2004 and 2003)2004) are invested in insurance policies on the lives of certain Company and affiliate personnel. Amounts for decommissioningThe Company transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest on proceeds, less expenses, are transferred by the Company to an external trust fund.expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
I.H. Income and Other Taxes
The Company is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including the Company, in the form of capital contributions. In 2005The Company received capital contributions under such provisions of $10.1 million in 2006 and $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 2003.2005.
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.I. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-termThe Company records long-term debt premium and discount are recorded in long-term debt and are being amortizedamortizes them as components of Interest Chargesinterest 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.J. 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.K. Cash and Cash Equivalents
The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and repurchase agreements.notes.
L.Commodity Derivatives
The Company hedges gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options. SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.
M. New Accounting StandardsMatters
SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaced SFAS 123, “Accounting for Stock-Based Compensation,” and superseded Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees.” The Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the Company’s results of operations is discussed at Note 3.
The Company adopted SFAS 154, “Accounting Changes and Error Corrections,” was issued in June 2005. Itthe first quarter of 2006. SFAS 154 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) OpinionAPB 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,Statements.” The adoption of SFAS 154 had no impact on the Company’s results of operations, cash flows or financial position.
SFAS 157, “Fair Value Measurements,” although it carries forward some of their provisions.was issued in September 2006. SFAS 157 establishes a framework for measuring fair value to increase the consistency and comparability in fair value measurements. The Company will adopt SFAS 154157 in the first quarter of 2006,2008, 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.
In September 2006, SFAS 158, “Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans,” amended SFAS 87 and SFAS 106 to require recognition of the overfunded or underfunded status of pension and other postretirement benefit plans on the balance sheet. Under SFAS 158, gains and losses, prior service costs and credits, and any remaining transition amounts under SFAS 87 and SFAS 106 that have not yet been recognized through net periodic benefit cost are to be recognized in accumulated other comprehensive income, net of tax effects, until they are amortized as a component of net periodic cost. The following table presents conditional asset retirement obligations and related assets as recorded in the Consolidated Balance SheetCompany adopted SFAS 158 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 nature2006. Because a significant amount of the business for which conditional asset retirement obligations were recognized,Company’s pension and other postretirement costs recorded under SFAS 87 and SFAS 106 are attributable to employees in its regulated operations, the adoption of FIN 47SFAS 158 primarily resulted in the recording of additional regulatory assets. The impact of adoption on the Company’s financial position is detailed at Note 3. The adoption did not have an impact on the Company’s results of operations or 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),159, “Share-Based Payment,The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in December 2004February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and will require compensation costs related to share-based payment transactionscertain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has not determined what impact, if any, that adoption will have on the Company’s results of operations, cash flows or financial position.
FIN 48, “Accounting for Uncertainty in Income Taxes,” was issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in thean enterprise’s 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 servicestatements in exchange for the award.accordance with SFAS 123(R) replaces SFAS 123, 109,“Accounting for Stock-Based Compensation”Income Taxes.” FIN 48 prescribes a recognition threshold and supersedes APB 25, “Accountingmeasurement attribute for Stock Issuedthe financial statement recognition and measurement of tax positions taken or expected to Employees.”be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company plans towill adopt SFAS 123(R)FIN 48 in the first quarter of 2007, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows and financial position.
FASB Staff Position (FSP) AUG AIR-1 “Accounting for Planned Major Maintenance Activities,” was issued in September 2006 and amends APB 28, “Interim Financial Reporting,” to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance in annual and interim financial reporting periods. As disclosed in Note 1A, the Company has received specific SCPSC orders providing for use of accrue-in-advance accounting for certain planned major maintenance activities. Accordingly, the Company will follow SFAS 71 when accounting for these activities. The Company will adopt FSP AUG AIR-1 in the first quarter of 2007, 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 PlanThe United States Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin 108 (SAB 108) in September 2006. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying and assessing the materiality of current year misstatements. SAB 108 also provides transition guidance for correcting errors existing from prior years. The Company adopted SAB 108 in December 2006. The adoption had no impact on the Company’s results of operations, cash flows or financial position.
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.
O.N. Affiliated Transactions
The Company has entered into agreements with certain affiliates to purchase all gas for resale to its distribution customers and to purchasefor generating electric energy. The Company purchasespurchased 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, 20052005. Effective November 1, 2006, SCG Pipeline, Inc. (SCG Pipeline) merged into SCPC and 2004, respectively.the merged company changed its name to Carolina Gas Transmission Corporation (CGTC). The Company had approximately $1.9 million payable to CGTC for transportation services at December 31, 2006.
In 2006, the Company purchased LNG facilities and LNG inventory from SCPC for approximately $17.1 million and $17.2 million, respectively. The Company also purchased underground gas storage inventory from SCPC for approximately $40.3 million. 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 20052006 and 20042005 was not significant. In 2003 such amounts were approximately $1.8 million.
The Company purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating Station from SCANA Energy Marketing, Inc. (SEMI).and to serve its retail gas customers. Such purchases totaled approximately $128.5$114.5 million and $79.7$128.5 million for the years ended December 31, 20052006 and 2004,2005, respectively. SCE&G had approximately $8.0$14.0 million and $4.5$8.0 million payable to SEMI for such purposes as of December 31, 200502006 and 2004,2005, 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$31.8 million and $18.6$24.6 million at December 31, 20052006 and 2004,2005, respectively. The Company had recorded as payables to these affiliated companies totaling approximately $25.3$26.6 million and $17.8$25.3 million at December 31, 20052006 and 2004,2005, respectively. The Company purchased approximately $291.1 million, $248.1 million $190.6 million and $145.2$190.6 million of synthetic fuel from these affiliated companies in 2006, 2005 and 2004, respectively. The Company made cash investments in these affiliated companies of $18.4 million in 2006, $17.7 million in 2005 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.$18.7 million in 2004. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.
Q.O. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. RATE AND OTHER REGULATORY MATTERS
Electric
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 Damback-up dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.
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 2006, 2005 2004 or 2003.2004.
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 20052006 and 20042005 was as follows:
Rate Per KWh | Effective Date |
$.01678 | January-April 2004 |
$.01821 | May-December 2004 |
$.01764 | January-April 2005 |
| $.02256 | May 2005-April 2006 |
| $.02516 | May-December 20052006 |
In connection with the May 2006 fuel component increase, SCE&G agreed to spread the recovery of previously undercollected fuel costs of $38.5 million over a two-year period.
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.
In June 2006, SCE&G’s&G reported to the SCPSC that its return on common equity for the twelve months ended March 31, 2006 was more than 0.5% below the allowed return, and as provided under South Carolina’s Natural Gas Rate Stabilization Act, SCE&G requested an annualized increase in certain natural gas base rates. In September 2006, the SCPSC approved an annual increase of $17.4 million. The rate adjustment was effective with the first billing cycle in November 2006.
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&G's cost of gas components by class were as follows (rate per therm):
| Effective Date | | Residential | | Small/Medium | | Large | |
| January-October 2005 | | | $.903 | | | $.903 | | | $.903 | |
| November 2005 | | | 1.297 | | | 1.222 | | | 1.198 | |
| December 2005 | | | 1.362 | | | 1.286 | | | 1.263 | |
| January 2006 | | | 1.297 | | | 1.222 | | | 1.198 | |
| February-October 2006 | | | 1.227 | | | 1.152 | | | 1.128 | |
| November 2006 | | | 1.115 | | | 1.004 | | | .963 | |
| December 2006 | | | 1.240 | | | 1.130 | | | 1.090 | |
In October 2006, the SCPSC approved a reduction in the 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 inof SCE&G’s cost ofretail natural 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, theThe SCPSC approved an increase in thealso authorized SCE&G to adjust its 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.on a monthly, rather than an annual, basis beginning in December 2006.
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 deferdefers certain MGP environmental costs in regulatory asset accounts and collectcollects and amortizeamortizes these costs through base rates.
3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension and Other Postretirement Benefit Plans
The Company participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all permanent employees. 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 SCANA's pension plan, which provided a final average pay formula, was amended to provide a cash balance formula for employees hired before January 1, 2000 who elected that option and for all new employees.employees hired on or after January 1, 2000. For employees who elected to remain under the final average pay formula, benefits are based on years of credited service and the employee's average annual base earnings received during the last three years of employment. For employees under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits.
In addition to pension benefits, the Company participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to active and retired employees. Retirees share in a portion of their medical care cost. 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 Company adopted the applicable benefits.balance sheet recognition provisions of SFAS 158 at December 31, 2006. The incremental effect of applying SFAS 158 on individual line items in the balance sheet was as follows:
| | | Before | | | | After | |
| | | Application of | | | | Application of | |
| December 31, 2006 | | SFAS 158 | | Adjustments | | SFAS 158 | |
Millions of dollars | | |
| Deferred debits - pension asset, net | | $ | 316.7 | | $ | (117.2 | ) | $ | 199.5 | |
| Deferred debits - regulatory assets | | | 575.2 | | | 127.1 | | | 702.3 | |
| Due from affiliates - pension and postretirement | | | 26.6 | | | 14.9 | | | 41.5 | |
| Deferred debits - other | | | 124.8 | | | 2.3 | | | 127.1 | |
| Total deferred debits | | | 1,070.1 | | | 27.1 | | | 1,097.2 | |
| Total assets | | | 7,599.2 | | | 27.1 | | | 7,626.3 | |
| Common equity | | | 2,464.1 | | | (6.7 | ) | | 2,457.4 | |
| Total shareholders’ investment | | | 2,570.4 | | | (6.7 | ) | | 2,563.7 | |
| Total capitalization | | | 4,585.6 | | | (6.7 | ) | | 4,578.9 | |
| Current liabilities - other | | | 49.5 | | | 12.9 | | | 62.4 | |
| Total current liabilities | | | 935.8 | | | 12.9 | | | 948.7 | |
| Deferred credits - deferred income taxes, net | | | 811.7 | | | (4.5 | ) | | 807.2 | |
| Deferred credits - postretirement benefits | | | 158.2 | | | 35.8 | | | 194.0 | |
| Due to affiliates - pension and postretirement | | | 9.0 | | | (3.5 | ) | | 5.5 | |
| Deferred credits - other | | | 74.2 | | | (6.9 | ) | | 67.3 | |
| Total deferred credits | | | 1,992.0 | | | 20.9 | | | 2,012.9 | |
| Total capitalization and liabilities | | | 7,599.2 | | | 27.1 | | | 7,626.3 | |
Funded Status
The funded status at the end of the year and the related amounts recognized on the balance sheets follow:
| | | Pension Benefits | | Other Postretirement Benefits | |
| | | December 31, | | December 31, | |
| | | 2006 | | 2005 | | 2006 | | 2005 | |
| | | Millions of Dollars | |
| Fair value of plan assets | | $ | 912.5 | | $ | 854.3 | | | - | | | - | |
| Benefit obligations | | | 713.0 | | | 711.4 | | $ | 206.9 | | $ | 202.1 | |
| Funded status | | | 199.5 | | | 142.9 | | | (206.9 | ) | | (202.1 | ) |
| Unrecognized net actuarial loss | | | n/a | | | 88.4 | | | n/a | | | 44.4 | |
| Unrecognized prior service cost | | | n/a | | | 71.3 | | | n/a | | | 5.2 | |
| Unrecognized transition obligation | | | n/a | | | 0.6 | | | n/a | | | 4.3 | |
| Amount recognized, end of year | | $ | 199.5 | | $ | 303.2 | | $ | (206.9 | ) | $ | (148.2 | ) |
Amounts recognized on the balance sheets consist of:
| Noncurrent asset | | $ | 199.5 | | | n/a | | | - | | | n/a | |
| Current liability | | | - | | | n/a | | $ | (12.9 | ) | | n/a | |
| Noncurrent liability | | | - | | | n/a | | | (194.0 | ) | | n/a | |
| Prepaid benefit cost | | | n/a | | $ | 303.2 | | | n/a | | | n/a | |
| Accrued benefit cost | | | n/a | | | - | | | n/a | | $ | (148.2 | ) |
Deferred amounts recognized in accumulated other comprehensive income, which is a component of common equity, as of December 31, 2006, including the adjustment above to reflect the adoption of SFAS 158, were as follows:
December 31, 2006 | | Pension Benefits | | Other Postretirement Benefits | | Total | |
| | | | | | | Millions of dollars | |
| Transition Obligation | | | - | | $ | 0.1 | | $ | 0.1 | |
| Prior Service Costs | | | - | | | 0.2 | | | 0.2 | |
| Actuarial Losses | | $ | 5.9 | | | 0.5 | | | 6.4 | |
| Total | | $ | 5.9 | | $ | 0.8 | | $ | 6.7 | |
The estimated transition obligation, prior service costs and actuarial losses for the defined benefit plans that will be amortized from accumulated other comprehensive income into net periodic benefit costs during 2007 are less than $100,000 in aggregate.
Changes in Benefit Obligations
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 | | | Retirement Benefits | | Other Postretirement Benefits | |
| | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Benefit obligation, January 1 | | $ | 669.5 | | $ | 619.9 | | $ | 197.5 | | $ | 188.4 | | | $ | 711.5 | | $ | 669.5 | | $ | 202.1 | | $ | 197.5 | |
| Service cost | | | 12.2 | | | 11.1 | | | 3.5 | | | 3.3 | | | | 14.0 | | | 12.2 | | | 4.6 | | | 3.5 | |
| Interest cost | | | 38.3 | | | 37.4 | | | 10.7 | | | 11.4 | | | | 39.8 | | | 38.3 | | | 11.5 | | | 10.7 | |
| Plan participants’ contributions | | | - | | | - | | | 2.3 | | | 1.1 | | | | - | | | - | | | 2.1 | | | 2.3 | |
| Plan amendments | | | - | | | 8.0 | | | (0.3 | ) | | 4.7 | | | | 0.6 | | | - | | | 4.0 | | | (0.3 | ) |
| Actuarial loss | | | 27.1 | | | 24.1 | | | 1.5 | | | 1.2 | | |
| Actuarial (gain) loss | | | | (14.4 | ) | | 27.1 | | | (5.5 | ) | | 1.5 | |
| Benefits paid | | | (35.6 | ) | | (31.0 | ) | | (13.1 | ) | | (12.6 | ) | | | (38.5 | ) | | (35.6 | ) | | (11.9 | ) | | (13.1 | ) |
| Benefit obligation, December 31 | | $ | 711.5 | | $ | 669.5 | | $ | 202.1 | | $ | 197.5 | | | $ | 713.0 | | $ | 711.5 | | $ | 206.9 | | $ | 202.1 | |
The accumulated benefit obligation for retirement benefits at the end of 2006 and 2005 and 2004 was $664.4$666.6 million and $635.8$664.4 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 | | | 2006 | | 2005 | |
| Annual discount rate used to determine benefit obligations | | | 5.60 | % | | 5.75 | % | | | 5.85 | % | | 5.60 | % |
| Assumed annual rate of future salary increases for projected benefit obligation | | | 4.00 | % | | 4.00 | % | | | 4.00 | % | | 4.00 | % |
A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005.2006. The rate was assumed to decrease gradually to 5.0% for 20122013 and to remain at that level thereafter. The effects of a one-percentage-point increase or decrease in the annual rate 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 | ) |
| | | 1% Increase | | 1% Decrease | |
| | | Millions of dollars | |
| Effect on postretirement benefit obligation | | $ | 3.1 | | $ | (2.7 | ) |
Changes in Plan Assets
| | | Retirement Benefits | | | Retirement Benefits | |
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Fair value of plan assets, January 1 | | $ | 846.7 | | $ | 787.7 | | | $ | 854.3 | | $ | 846.7 | |
| Actual return on plan assets | | | 43.2 | | | 90.0 | | | | 96.7 | | | 43.2 | |
| Benefits paid | | | (35.6 | ) | | (31.0 | ) | | | (38.5 | ) | | (35.6 | ) |
| Fair value of plan assets, December 31 | | $ | 854.3 | | $ | 846.7 | | | $ | 912.5 | | $ | 854.3 | |
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. At the end of 20052006 and 2004,2005, 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, 20052006 and 2004,2005, the Company recorded within deferred credits a $10.2$3.6 million and $9.7$10.2 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, 20052006 and 2004,2005, the Company also recorded within deferred debits a $7.1$9.9 million and $6.8$7.1 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* | | | | | Other Postretirement Benefits* | |
Expected Benefit Payments | | Pension Benefits | | Excluding Medicare Subsidy | | Including Medicare Subsidy | | | Pension Benefits | | Excluding Medicare Subsidy | | Including Medicare Subsidy | |
| | | Millions of dollars | | | Millions of dollars | |
| 2006 | | $ | 35.9 | | $ | 8.6 | | $ | 8.3 | | |
| 2007 | | | 37.7 | | | 9.2 | | | 8.9 | | | $ | 39.7 | | $ | 10.0 | | $ | 9.7 | |
| 2008 | | | 39.6 | | | 9.7 | | | 9.3 | | | | 40.1 | | | 10.3 | | | 10.0 | |
| 2009 | | | 41.6 | | | 10.0 | | | 9.6 | | | | 40.5 | | | 10.3 | | | 10.0 | |
| 2010 | | | 43.6 | | | 10.3 | | | 10.0 | | | | 40.9 | | | 10.6 | | | 10.3 | |
| 2011-2015 | | | 253.5 | | | 55.1 | | | 53.4 | | |
| 2011 | | | | 41.3 | | | 10.8 | | | 10.4 | |
| 2012-2016 | | | | 212.8 | | | 57.4 | | | 56.0 | |
*Net of participant contributions
Net Periodic Cost
As allowed by SFAS 87 and SFAS 106, as amended, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans under SFAS 132, “Employer’s Disclosures about Pensions and Other Postretirement Benefits,” as amended, are set forth in the following tables.
Components of Net Periodic Benefit Cost (Income)
| | | Retirement Benefits | | Other Postretirement Benefits | | | Retirement Benefits | | Other Postretirement Benefits | |
| | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| | | Millions of dollars | | | Millions of dollars | |
| Service cost | | $ | 12.2 | | $ | 11.1 | | $ | 9.5 | | $ | 3.5 | | $ | 3.3 | | $ | 2.7 | | | $ | 14.0 | | $ | 12.2 | | $ | 11.1 | | $ | 4.6 | | $ | 3.5 | | $ | 3.3 | |
| Interest cost | | | 38.3 | | 37.4 | | 36.7 | | 10.7 | | 11.4 | | 11.4 | | | | 39.8 | | 38.3 | | 37.4 | | 11.5 | | 10.7 | | 11.4 | |
| Expected return on assets | | | (76.3 | ) | | (71.0 | ) | | (59.9 | ) | | n/a | | n/a | | n/a | | | | (75.2 | ) | | (76.3 | ) | | (71.0 | ) | | n/a | | n/a | | n/a | |
| Prior service cost amortization | | | 6.9 | | 6.6 | | 6.3 | | 0.8 | | 1.4 | | 0.9 | | | | 6.8 | | 6.9 | | 6.6 | | 1.1 | | 0.8 | | 1.4 | |
| Actuarial loss | | | - | | - | | 1.6 | | 1.2 | | 1.9 | | 1.5 | | |
| Amortization of actuarial loss | | | | 0.5 | | - | | - | | 1.7 | | 1.2 | | 1.9 | |
| Transition amount amortization | | | 0.8 | | 0.8 | | 0.8 | | 0.8 | | 0.8 | | 0.8 | | | | 0.6 | | 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 | ) | | | (2.5 | ) | | (1.9 | ) | | (1.7 | ) | | (5.4 | ) | | (4.8 | ) | | (5.5 | ) |
| Net periodic benefit (income) cost | | $ | (20.0 | ) | $ | (16.8 | ) | $ | (6.8 | ) | $ | 12.2 | | $ | 13.3 | | $ | 12.0 | | | $ | 16.0 | | $ | (20.0 | ) | $ | (16.8 | ) | $ | 14.3 | | $ | 12.2 | | $ | 13.3 | |
Significant Assumptions Used in Determining Net Periodic Benefit Cost (Income)
| | | Retirement Benefits | | Other Postretirement Benefits | | | Retirement Benefits | | Other Postretirement Benefits | |
| | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| Discount rate | | | 5.75 | % | | 6.00 | % | | 6.50 | % | | 5.75 | % | | 6.00 | % | | 6.50 | % | | | 5.60 | % | | 5.75 | % | | 6.00 | % | | 5.60 | % | | 5.75 | % | | 6.00 | % |
| Expected return on plan assets | | | 9.25 | % | | 9.25 | % | | 9.25 | % | | n/a | | n/a | | n/a | | | | 9.00 | % | | 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 | % | | | 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 | % | | | n/a | | n/a | | | n/a | | | 9.00 | % | | 9.00 | % | | 9.50 | % |
| Ultimate health care cost trend rate | | | n/a | | n/a | | n/a | | 5.00 | % | | 5.00 | % | | 5.00 | % | | | n/a | | n/a | | | n/a | | | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Year achieved | | | n/a | | n/a | | n/a | | 2011 | | 2011 | | 2011 | | | | n/a | | n/a | | | n/a | | | 2012 | | | 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, 20052006 and 20042005 and the target allocations for 20062007 are as follows:
| | | Target Allocation | | Percentage of Plan Assets At December 31, | | | Target Allocation | | Percentage of Plan Assets At December 31, | |
Asset Category | | 2006 | | 2005 | | 2004 | | | 2007 | | 2006 | | 2005 | |
| Equity Securities | | | 70 | % | | 72 | % | | 72 | % | | | 70 | % | | 72 | % | | 72 | % |
| Debt Securities | | | 30 | % | | 28 | % | | 28 | % | | | 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.
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%9.0% 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 20062007 the expected rate of return will be 9.0%.
Share-Based Compensation
The Company participates in the SCANA Long-Term Equity Compensation Plan provides for grants of incentive nonqualified stock options, stock appreciation rights, restricted stock, performance shares and performance units to certain key employees and non-employee directors. The plan currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.
SFAS 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $4 million (net of tax) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.
Liability Awards
Through 2006, certain executives were granted a target number of performance shares on an annual basis that vest over a three-year period. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. Payout of performance share awards is determined by SCANA's performance against pre-determined measures of total shareholder return (TSR) as compared to a peer group of utilities (weighted 60%) and growth in earnings per share (weighted 40%) over the three year plan cycle. TSR is calculated by dividing stock price change over the three-year period, plus cash dividends, by the stock price as of the beginning of the period. Payouts vary according to SCANA's ranking against the peer group and relative earnings per share projection achievement. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.
Under SFAS 123(R) compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $1.2 million were paid during the twelve months ended December 31, 2006. No such payments were made in 2005.
Fair value adjustments for performance awards resulted in a reduction to compensation expense recognized in the condensed statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $(4.8) million for the year ended December 31, 2006, and increases to compensation expense totaling $2.3 million and $8.4 million for the years ended December 31, 2005 and 2004, respectively. Fair value adjustments resulted in a net credit to capitalized compensation cost of approximately $(0.7) million during the year ended December 31, 2006, compared to capitalized costs of approximately $0.3 million in 2005 and $1.8 million in 2004.
Equity Awards
A summary of activity related to nonqualified stock options since December 31, 2003 follows:
| | | Number of Options | | Weighted Average Exercise Price | |
| 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 | | | (291,177 | ) | $ | 27.48 | |
| Forfeited | | | - | | | - | |
| Outstanding- December 31, 2005 | | | 439,270 | | $ | 27.53 | |
| Exercised | | | (53,330 | ) | $ | 27.52 | |
| Forfeited | | | - | | | - | |
| Outstanding- December 31, 2006 | | | 385,940 | | $ | 27.56 | |
No stock options have been granted since August 2002, and all options were fully vested in August 2005. The options expire ten years after the grant date. At December 31, 2006, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 4.9 years.
All options were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense was recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123(R), pro forma earnings available for the common shareholder for the years ended December 31, 2005 and 2004 would have been as follows:
| | | | 2005 | | 2004 | |
| Earnings Available for Common Shareholder-as reported (millions) | | | $ | 250.8 | | $ | 225.2 | |
| Earnings Available for Common Shareholder-pro forma (millions) | | | | 250.6 | | | 224.1 | |
The exercise of stock options during the period was satisfied using original issue shares of SCANA’s common stock. Cash and the related tax benefits realized from stock option exercises during the period were retained at SCANA. Beginning in 2007, the Company will satisfy the exercise of stock options using open market purchases of common stock, rather than original issue of shares. The Company estimates that 200,000 common shares will be repurchased in 2007 due to the exercise of stock options.
4. LONG-TERM DEBT
Long-term debt by type with related weighted average interest rates and maturities is as follows:
| | Weighted-Average | Maturity | December 31, | | Weighted-Average | | Maturity | | December 31, | |
| | Interest Rate | Date | 2005 | 2004 | | Interest Rate | | Date | | 2006 | | 2005 | |
| | | | Millions of dollars | | | | | | Millions of dollars | |
| First Mortgage Bonds (secured) | 5.98% | 2009-2035 | $1,550 | $1,700 | | | 6.00 | % | | 2009-2036 | | $ | 1,675 | | $ | 1,550 | |
| First & Refunding Mortgage Bonds (secured) | 9.00% | 2006 | 131 | 131 | | | 9.00 | % | | 2006 | | | - | | | 131 | |
| GENCO Notes (secured) | 5.97% | 2011-2024 | 127 | 130 | | | 5.92 | % | | 2011-2024 | | | 123 | | | 127 | |
| Industrial and Pollution Control Bonds | 5.24% | 2012-2032 | 156 | 156 | | | 5.24 | % | | 2012-2032 | | | 156 | | | 156 | |
| Other | | 2006-2014 | 97 | 81 | | | | | | 2007-2014 | | | 80 | | | 97 | |
| Total debt | | | 2,061 | 2,198 | | | | | | | | | 2,034 | | | 2,061 | |
| Current maturities of long-term debt | | | (183) | (198) | | | | | | | | | (13 | ) | | (183 | ) |
| Unamortized discount | | | (22) | (19) | | | | | | | | | (13 | ) | | (22 | ) |
| Total long-term debt, net | | | $1,856 | $1,981 | | | | | | | | $ | 2,008 | | $ | 1,856 | |
The annual amounts of long-term debt maturities and sinking fund requirements for the years 20062007 through 20102011 are summarized as follows:
Year | | Millions of dollars | |
| | |
| 2007 | | $ | 13 | |
| 2008 | | | 13 | |
| 2009 | | | 138 | |
| 2010 | | | 16 | |
| 2011 | | | 171 | |
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 underUnder 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 fundsborrowed an aggregate $59 million from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediationback-up dam project. Such borrowings are being repaid interest-free over ten years from the initial borrowing.years. At December 31, 2006 and 2005, SCE&G had $44.3 million and $50.2 million outstanding under the agreement.agreement, respectively.
Substantially all of SCE&G's and GENCO's electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.
5. LINES OF CREDIT AND SHORT-TERM BORROWINGS
Details of lines of credit and short-term borrowings at December 31, 20052006 and 2004,2005, are as follows:
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Lines of credit (total and unused) | | | | | | | | | | |
| Committed | | $ | 525 | | $ | 525 | | | $ | 650 | | $ | 525 | |
Uncommitted | | | 78(a | ) | | 113(a | ) | | | 78 | | | 78 | |
| Short-term borrowings outstanding | | | | | | | | | | | | | | |
| Commercial paper (270 or fewer days) | | $ | 303.1 | | $ | 152.9 | | | $ | 362.2 | | $ | 303.1 | |
| Weighted average interest rate | | | 4.40 | % | | 2.40 | % | | | 5.38 | % | | 4.40 | % |
(a) LinesLine 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.December 19, 2011.
Fuel Company commercial paper outstanding totaled $106.7$123.7 million and $31.3$106.7 million at December 31, 20052006 and 2004,2005, respectively, at weighted average interest rates of 4.39%5.38% and 2.44%4.39%, respectively.
SCE&G’s commercial paper outstanding totaled $196.4$238.5 million and $121.6$196.4 million at December 31, 20052006 and 2004,2005, respectively, at weighted average interest rates of 4.40%5.38% and 2.39%4.40%, 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
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2005, $512006, $54 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 20062007 through 20102011 is $2.6$2.5 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 20052006 SCE&G had shares of preferred stock authorized and available for issuance as follows:
Par Value | Authorized | Available for Issuance | Authorized | Available for Issuance |
| $100 | 1,000,000 | - | 1,000,000 | - |
| $ 50 | 601,613 | 300,000 | 592,405 | 300,000 |
| $ 25 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 |
Preferred Stock (Not subject to purchase or sinking funds)
For each of the three years ended December 31, 2005,2006, SCE&G had outstanding 1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par Cumulative Preferred Stock (not subject to purchase or sinking funds).
Preferred Stock (Subject to purchase or sinking funds)
Changes in “Total Preferred Stock (Subject to purchase or sinking funds)” during 2006, 2005 2004 and 20032004 are summarized as follows:
| | Series | | | | Series | | | | | |
| | 4.50%, 4.60% (A) & 5.125% | 4.60% (B) & 6.00% | Total Shares | Millions of Dollars | | 4.50%, 4.60% (A) & 5.125% | | 4.60% (B) & 6.00% | | Total Shares | | Millions of Dollars | |
Redemption Price | $51.00 | $50.50 | | | | $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 | | | 81,034 | | 112,561 | | 193,595 | | $ | 9.7 | |
| Shares Redeemed-$50 par value | (2,516) | (6,600) | (9,116) | (0.5) | | | (2,516 | ) | | (6,600 | ) | | (9,116 | ) | | (0.5 | ) |
| Balance at December 31, 2004 | 78,518 | 105,961 | 184,479 | 9.2 | | | 78,518 | | 105,961 | | 184,479 | | 9.2 | |
| Shares Redeemed-$50 par value | (1,475) | (6,600) | (8,075) | (0.4) | | | (1,475 | ) | | (6,600 | ) | | (8,075 | ) | | (0.4 | ) |
| Balance at December 31, 2005 | 77,043 | 99,361 | 176,404 | $8.8 | | | 77,043 | | 99,361 | | 176,404 | | 8.8 | |
| Shares Redeemed-$50 par value | | | | (2,608 | ) | | (6,600 | ) | | (9,208 | ) | | (0.5 | ) |
| Balance at December 31, 2006 | | | | 74,435 | | | 92,761 | | | 167,196 | | $ | 8.3 | |
8. INCOME TAXES
Total income tax expense (benefit) attributable to income (before cumulative effect of accounting change) for 2006, 2005 2004 and 20032004 is as follows:
| | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| | | Millions of dollars | | | Millions of dollars | |
| Current taxes: | | | | | | | | | | | | | | |
| Federal | | $ | (8.4 | ) | $ | 47.4 | | $ | 23.7 | | | $ | 69.6 | | $ | (8.4 | ) | $ | 47.4 | |
| State | | | 9.5 | | | (4.4 | ) | | 8.5 | | | | 5.3 | | | 9.5 | | | (4.4 | ) |
| Total current taxes | | | 1.1 | | | 43.0 | | | 32.2 | | | | 74.9 | | | 1.1 | | | 43.0 | |
| Deferred taxes, net: | | | | | | | | | | | | | | | | | | | | |
| Federal | | | (7.5 | ) | | 28.1 | | | 41.7 | | | | 8.6 | | | (7.5 | ) | | 28.1 | |
| State | | | (9.8 | ) | | 4.1 | | | 0.7 | | | | 5.2 | | | (9.8 | ) | | 4.1 | |
| Total deferred taxes | | | (17.3 | ) | | 32.2 | | | 42.4 | | | | 13.8 | | | (17.3 | ) | | 32.2 | |
| Investment tax credits: | | | | | | | | | | | | | | | | | | | | |
| Deferred-state | | | 5.1 | | | 10.0 | | | 5.0 | | | | 5.0 | | | 5.1 | | | 10.0 | |
| Amortization of amounts deferred-state | | | (1.9 | ) | | (2.1 | ) | | (1.8 | ) | | | (3.3 | ) | | (1.9 | ) | | (2.1 | ) |
| Amortization of amounts deferred-federal | | | (2.7 | ) | | (3.6 | ) | | (3.6 | ) | | | (2.7 | ) | | (2.7 | ) | | (3.6 | ) |
| Total investment tax credits | | | 0.5 | | | 4.3 | | | (0.4 | ) | | | (1.0 | ) | | 0.5 | | | 4.3 | |
| Synthetic fuel tax credits - federal | | | (134.2 | ) | | 40.5 | | | 35.7 | | | | - | | | (134.2 | ) | | 40.5 | |
| Total income tax expense (benefit) | | $ | (149.9 | ) | $ | 120.0 | | $ | 109.9 | | | $ | 87.7 | | $ | (149.9 | ) | $ | 120.0 | |
The difference between actual income tax expense (benefit) and that amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income (before cumulative effect of accounting change) is reconciled as follows:
| | | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| | | Millions of dollars | | | Millions of dollars | |
| Net income | | $ | 258.1 | | $ | 232.5 | | $ | 220.5 | | | $ | 230.0 | | $ | 258.1 | | $ | 232.5 | |
| Income tax expense (benefit) | | | (149.9 | ) | | 120.0 | | | 109.9 | | | | 87.7 | | | (149.9 | ) | | 120.0 | |
| Minority interest | | | 5.5 | | | 10.3 | | | 8.0 | | | | 7.0 | | | 5.5 | | | 10.3 | |
| Total pre-tax income | | | 113.7 | | | 362.8 | | $ | 338.4 | | | | 324.7 | | | 113.7 | | | 362.8 | |
| Income taxes on above at statutory federal income tax rate | | $ | 39.8 | | $ | 127.0 | | $ | 118.4 | | | $ | 113.6 | | $ | 39.8 | | $ | 127.0 | |
| Increases (decreases) attributed to: | | | | | | | | | | | | | | | | | | | | |
| State income taxes (less federal income tax effect) | | | 1.9 | | | 4.9 | | | 8.0 | | | | 7.9 | | | 1.9 | | | 4.9 | |
| Synthetic fuel tax credits | | | (181.9 | ) | | (2.9 | ) | | (2.2 | ) | | | (33.5 | ) | | (181.9 | ) | | (2.9 | ) |
| Allowance for equity funds used during construction | | | - | | | (5.0 | ) | | (6.2 | ) | | | 0.1 | | | - | | | (5.0 | ) |
| Non-taxable recovery of Lake Murray Dam project carrying costs | | | (3.8 | ) | | - | | | - | | |
| Non-taxable recovery of Lake Murray back-up dam project carrying costs | | | | (2.3 | ) | | (3.8 | ) | | - | |
| Amortization of federal investment tax credits | | | (2.7 | ) | | (3.6 | ) | | (3.6 | ) | | | (2.7 | ) | | (2.7 | ) | | (3.6 | ) |
| Amended returns for prior years | | | (2.1 | ) | | - | | | - | | | | - | | | (2.1 | ) | | - | |
| Other differences, net | | | (1.1 | ) | | (0.4 | ) | | (4.5 | ) | | | 4.6 | | | (1.1 | ) | | (0.4 | ) |
| Total income tax expense (benefit) | | $ | (149.9 | ) | $ | 120.0 | | $ | 109.9 | | | $ | 87.7 | | $ | (149.9 | ) | $ | 120.0 | |
The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $788.2 million at December 31, 2006 and $778.2 million at December 31, 2005 and $759.0 million at December 31, 2004 (see Note 1I) are as follows:
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Millions of dollars | | | Millions of dollars | |
| Deferred tax assets: | | | | | | | | | | |
| Nondeductible reserves | | $ | 72.1 | | $ | 68.8 | | | $ | 90.6 | | $ | 72.1 | |
| Unamortized investment tax credits | | | 59.2 | | | 59.9 | | | | 58.2 | | | 59.2 | |
| Federal alternative minimum tax credit carryforward | | | 44.0 | | | 12.3 | | | | 22.1 | | | 44.0 | |
| Deferred compensation | | | 25.4 | | | 22.0 | | | | 25.0 | | | 25.4 | |
| Unbilled revenue | | | 16.4 | | | 7.0 | | | | 10.5 | | | 16.4 | |
| Other | | | 8.6 | | | 5.6 | | | | 9.0 | | | 8.6 | |
| Total deferred tax assets | | | 225.7 | | | 175.6 | | | | 215.4 | | | 225.7 | |
| Deferred tax liabilities: | | | | | | | | | | | | | | |
| Property, plant and equipment | | | 824.5 | | | 789.5 | | | | 828.9 | | | 824.5 | |
| Pension plan benefit income | | | 110.5 | | | 102.4 | | |
| Pension plan income | | | | 74.1 | | | 110.5 | |
| Deferred employee benefit plan costs | | | | 50.5 | | | - | |
| Deferred fuel costs | | | 44.5 | | | 21.6 | | | | 25.7 | | | 44.5 | |
| Other | | | 24.4 | | | 21.1 | | | | 24.4 | | | 24.4 | |
| Total deferred tax liabilities | | | 1,003.9 | | | 934.6 | | | | 1,003.6 | | | 1,003.9 | |
| Net deferred tax liability | | $ | 778.2 | | $ | 759.0 | | | $ | 788.2 | | $ | 778.2 | |
Previously, theThe Internal Revenue Service hadhas completed and closed examinations of the Company's consolidated federal income tax returns through tax years ending in 2000. In 2005,2004, and the Company filed amended federal incomeCompany’s tax returns through 2001 are closed 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.additional assessment. The IRS has also closed the examination ofis currently examining S. C. Coaltech No. 1 L.P.LP., a synthetic fuel partnership in which the Company has an interest, for the 20002004 tax year, resulting inyear. The Company does not anticipate that return being accepted as filed.any adjustments which might result from the examination will have a material impact on the earnings or the financial position of the Company. 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.
9. FINANCIAL INSTRUMENTS
Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 20052006 and 20042005 were as follows:
| | | 2005 | | 2004 | | | 2006 | | 2005 | |
| | | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value | | | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value | |
| | | Millions of dollars | | | Millions of dollars | |
| Long-term debt | | $ | 2,038.3 | | $ | 2,125.8 | | $ | 2,179.4 | | $ | 2,347.6 | | | $ | 2,021.0 | | $ | 2,068.0 | | $ | 2,038.3 | | $ | 2,125.8 | |
| Preferred stock (subject to purchase or sinking funds) | | | 8.2 | | | 8.2 | | | 9.2 | | | 8.5 | | | | 8.3 | | | 7.8 | | 8.8 | | | 8.2 | |
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. |
Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.
The Company’s regulated gas operations hedge gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. The Company’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, the cost of related derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the charge in fair value of these derivatives is recorded as a regulatory asset or liability.
In anticipation of the issuance of debt, the Company also usesmay use interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments received or made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuanceAs permitted by SFAS 104 “Statement of First Mortgage Bonds in May 2003, the Company paid $11.9 million upon the terminationCash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions,” payments received or made are classified as a 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 agreementfinancing activity in the amountconsolidated statement 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.cash flows.
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$15 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$14.1 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G’s rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. IfHowever, 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. TheAlthough the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is reviewinguncertain as to how the final rule. InstallationPhase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls is likely towill be required to comply with the rule’s Phase II mercury rule’s emission caps. ComplianceFinal compliance plans and costs to comply with the rule will be determined once the Company completes itsare still under review. Such costs will be material and are expected to be recoverable through rates.
SCE&G has been named, along with 29 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, purchase of new transformers and sale of used 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. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.
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$17.9 million at December 31, 2005.2006. 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 remediation for contamination at the remaining remediation activitiessite will be completed by mid-2006,in 2007, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005,2006, the Company hashad spent approximately $21.5$22.3 million to remediate the Calhoun Park site and expects to spend an additional $0.3 million.$1.1 million prior to entering a monitoring and reporting stage. 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. AnySCE&G expects to recover any cost arising from the remediation of this matter is expected to be recoverablesite 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 2010.2011. As of December 31, 2005,2006, the Company has spent approximately $4.5$4.8 million related to these three sites, and expects to spend an additional $11.5$11.2 million. AnySCE&G expects to recover any cost arising from this matter is expected to be recoverablethe remediation of these sites 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.
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
OnIn August 21, 2003, the CompanySCE&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’sCarolina'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-utilitynonutility third parties or telecommunication companies for other than the electric utilities’utility’s internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may not go to trial in 2006. The Company isbefore 2008. SCANA and SCE&G are confident of the propriety of itsSCE&G’s actions and intend to mount a vigorous defense. The CompanySCANA and SCE&G further believesbelieve that the resolution of these claims will not have a material adverse impact on itstheir results of operations, cash flows or financial condition.
OnIn May 17, 2004, the Company wasSCANA 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’sCarolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit Court (the Court).Circuit. The plaintiff alleges the CompanySCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than the Company’sSCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes itsSCANA and SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted the Company’sSCANA’s and SCE&G’s motion to dismiss and issued an order dismissing the case onin June 29, 2005. The plaintiff has appealed.appealed to the South Carolina Supreme Court. The Company intendsSupreme Court overruled the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration. It is anticipated that this case may not go to trial before 2008. SCANA and SCE&G will continue to mount a vigorous defense and believebelieves 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 onin 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’smunicipality'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.claim against SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by South Carolina’s Circuit Court of Common Pleas for the 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.Fifth Judicial Circuit. In addition, the CompanySCE&G filed a petition with the SCPSC onin 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’sSCE&G’s electric and gas service, to approve the Company’sSCE&G’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material loss toadverse impact on the Company.Company’s results of operations, cash flows or financial condition.
E. Other ContingencySettlement Related to Power Marketing Practices
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, 2006,18, 2007, FERC approved a settlement with SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgmentregarding the use of SCE&G’s discovery that it may have improperly utilizedelectric transmission system by its power marketing division. SCE&G identified, investigated and self-reported instances of improper utilization of 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 FERC orders under the Federal Power Act that prohibit the use of network transmission service in support of certain “off-system” sales. This acknowledgement
As part of the settlement, SCE&G agreed that it would not retain any benefit derived from the transactions. SCE&G paid a $9 million penalty to the U.S. Treasury. Additionally, SCE&G agreed to credit an additional $1.4 million to benefit retail native load ratepayers and SCE&G’s non-affiliated firm transmission customers. The credit to the retail native load ratepayers was applied toward the fuel clause mechanism in partJanuary 2007. The credit to the resultnon-affiliated firm transmission customers was refunded directly to those customers. An additional $0.4 million was credited to transmission revenue to the benefit 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 dateretail rate payers. The effects 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 theresettlement were approximately 1,200 of these transactions since August 8, 2005, that, despite the immaterial profits from the transactions, could be deemedaccrued 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.2006.
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 2010.2009. Rent expense totaled approximately $11.7$12.8 million, $9.9$11.7 million and $9.9 million in 2006, 2005 2004 and 2003,2004, respectively. Future minimum rental payments under such leases are as follows:
| | | Millions of dollars | | | Millions of dollars | |
| 2006 | | $ | 13 | | |
| 2007 | | | 11 | | | $ | 27 | |
| 2008 | | | 10 | | | | 13 | |
| 2009 | | | 9 | | | | 9 | |
| 2010 | | | 1 | | |
| Thereafter | | | | - | |
| | | $ | 44 | | | $ | 49 | |
At December 31, 2005,2006, minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $6.9$5.7 million.
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 $526.0 million, $439.4 million and $348.3 million in 2006, 2005 and $276.5 million in 2005, 2004, and 2003, respectively. Future payments under such purchase commitments are as follows:
| | | Millions of dollars | | | Millions of dollars | |
| 2006 | | $ | 414 | | |
| 2007 | | | 164 | | | $ | 689 | |
| 2008 | | | 92 | | | | 359 | |
| 2009 | | | 35 | | | | 489 | |
| 2010 | | | 7 | | | | 49 | |
| 2011 | | | | 18 | |
| Thereafter | | | 55 | | | | 106 | |
| | | $ | 767 | | | $ | 1,710 | |
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.
H.Asset Retirement Obligations
In accordance with SFAS 143, “Accounting for Asset Retirement Obligations,” as interpreted by FIN 47, “Accounting for Conditional Asset Retirement Obligations,” the Company recognizes a liability for the fair value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation and relates primarily to the Company’s regulated utility operations. As of December 31, 2006, the Company has recorded an ARO of approximately $92 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $185 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:
| Millions of dollars | | 2006 | | 2005 | |
| Beginning balance | | $ | 309 | | $ | 124 | |
| Liabilities incurred | | | 1 | | | - | |
| Liabilities settled | | | (1 | ) | | - | |
| Accretion expense | | | 16 | | | 7 | |
| Revisions in estimated cash flows | | | (46 | ) | | - | |
| Adoption of FIN 47 | | | - | | | 178 | |
| Ending Balance | | $ | 279 | | $ | 309 | |
Revisions in estimated cash flows relate to the estimated ARO associated with decommissioning Summer Station. The reduction is primarily related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis.
11. SEGMENT OF BUSINESS INFORMATION
The Company’s reportable segments are Electric Operations and Gas Distribution. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations is primarily engaged in the generation, transmission, and distribution of electricity, and is regulated by the SCPSC and FERC. Gas Distribution is engaged in the purchase and sale, primarily at retail, of natural gas, and is regulated by the SCPSC.
Disclosure of Reportable Segments (Millions of dollars)
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 | |
2006 | | | Electric Operations | | Gas Distribution | | All Other | | Adjustments/ Eliminations | | Consolidated Total | |
| Customer Revenue | $1,692 | $397 | - | - | $2,089 | | $ | 1,886 | | $ | 505 | | - | | - | | $ | 2,391 | |
| Intersegment Revenue | - | 1 | - | $(1) | - | | | - | | 3 | | - | | (3 | ) | | - | |
| Operating Income (Loss) | 550 | 14 | - | (89) | 475 | | | 456 | | 25 | | - | | (13 | ) | | 468 | |
| Interest Expense | 10 | - | - | 129 | 139 | | | 15 | | - | | - | | 125 | | 140 | |
| Depreciation and Amortization | 208 | 13 | - | - | 221 | | | 268 | | 18 | | - | | - | | 286 | |
| Segment Assets | 5,365 | 354 | $3 | 1,263 | 6,985 | | | 5,520 | | 440 | | - | | 1,666 | | 7,626 | |
| Expenditures for Assets | 389 | 35 | - | 15 | 439 | | | 304 | | 83 | | - | | 25 | | 412 | |
| Deferred Tax Assets | n/a | n/a | - | 5 | | | n/a | | n/a | | - | | 19 | | 19 | |
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 | | | | | | | | | | | |
| 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 | |
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 revenueoperating revenues remove revenues from non-reportable segments. Segment assetsAssets 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 | | |
2006 Millions of dollars | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Annual | |
| Total operating revenues | | $ | 573 | | $ | 523 | | $ | 696 | | $ | 629 | | $ | 2,421 | | | $ | 592 | | $ | 553 | | $ | 664 | | $ | 582 | | $ | 2,391 | |
| Operating income (loss) | | | (59 | ) | | 78 | | 178 | | 115 | | 312 | | |
| Operating income | | | | 103 | | 113 | | 159 | | 93 | | 468 | |
| Income before cumulative effect of accounting change | | | | 46 | | 53 | | 93 | | 38 | | 230 | |
Cumulative effect of accounting change, net of taxes (1) | | | | 4 | | - | | - | | - | | 4 | |
| Net income | | | 52 | | 40 | | 106 | | 62 | | 260 | | | | 50 | | 53 | | 93 | | 38 | | 234 | |
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 | |
2005 Millions of dollars | | | | | | | | | | | |
| Total operating revenues | | $ | 573 | | $ | 523 | | $ | 696 | | $ | 629 | | $ | 2,421 | |
| Operating income (loss) | | | (59 | ) | | 78 | | | 178 | | | 115 | | | 312 | |
| Net income | | | 52 | | | 40 | | | 106 | | | 60 | | | 258 | |
OF NORTH CAROLINA, INCORPORATED
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Item 7. | | 141 |
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Item 7A. | | 144 |
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Item 8. | | |
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| | | 147 |
| | | 149 |
| | | 150 |
| | | 151 |
| | | 152 |
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Public Service CompanyThe cumulative effect of North Carolina, Incorporated meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and thereforeaccounting change is filing this form with the reduced disclosure format allowed under General Instruction I(2).
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 limitedattributable 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.
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.
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.
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 $13 million for other conditional obligations related to gas pipeline properties which was recorded under FIN 47. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. Changes in these estimates will be recorded over time, but as stated above, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for PSNC Energy remains in place.
All financial instruments held by PSNC Energy described below are held for purposes other than trading.
Interest rate risk—The tables below provide information about long-term debt issued by PSNC Energy and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.
| | Expected Maturity Date |
December 31, 2005 Millions of dollars | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | Fair Value |
| Liabilities | | | | | | | | |
| Long-Term Debt: | | | | | | | | |
| Fixed Rate ($) | 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 ($) | 3.2 | 3.2 | 3.2 | 3.2 | 3.2 | 6.4 | 22.4 | 0.4 |
| Average Pay Interest Rate (%) | 7.7 | 7.7 | 7.7 | 7.7 | 7.7 | 7.7 | 7.7 | |
| Average Receive Interest Rate (%) | 8.75 | 8.75 | 8.75 | 8.75 | 8.75 | 8.75 | 8.75 | |
| | Expected Maturity Date |
December 31, 2004 Millions of dollars | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | Fair Value |
| Liabilities | | | | | | | | |
| Long-Term Debt: | | | | | | | | |
| Fixed Rate ($) | 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.
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
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 | |
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.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
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.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
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.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
| | | | | | |
| | | | | | |
| | | | | | |
| | | | 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.
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.
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.
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.
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 154123(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.
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.
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.2006. See
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.
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.
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 | |
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.
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 |
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 Millions of 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 Millions of 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 | |
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.
SCANA:
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2005,2006, an evaluation was performed under the supervision and with the participation of SCANA's management, including the CEOChief Executive Officer (CEO) and CFO,Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCANA's management, including the CEO and CFO, concluded that SCANA's disclosure controls and procedures were effective as of December 31, 2005.2006. There has been no change in SCANA's internal controls over financial reporting during the quarter ended December 31, 20052006 that has materially affected or is reasonably likely to materially affect SCANA's internal control over financial reporting.
Management's Evaluation of Internal Control Over Financial Reporting:
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2006, the effectiveness of such structure and procedures. This management report follows.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of SCANA Corporation (SCANA) is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA's internal control system was designed by or under the supervision of SCANA’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), to provide reasonable assurance to SCANA's management and board of directors regarding the reliability of financial reporting and the preparation and fair presentation of published financial statements.statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.
SCANA's management assessed the effectiveness of SCANA's internal control over financial reporting as of December 31, 2005.2006. 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, 2005,2006, 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
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, 2005,2006, 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, 2005,2006, 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, 2005,2006, 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, 2005,2006, of SCANA Corporation and subsidiaries and our report dated March 1, 2006,February 28, 2007, expressed an unqualified opinion on those financial statements and financial statement schedule.schedule and included an explanatory paragraph regarding the Company's adoption of Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans."
/s/DELOITTE & TOUCHE LLP
Columbia, South Carolina
March 1, 2006February 28, 2007
SCE&G:
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2005,2006, an evaluation was performed under the supervision and with the participation of SCE&G's management, including the CEO and CFO, of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that SCE&G's disclosure controls and procedures were effective as of December 31, 2005.2006. There has been no change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 20052006 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.
Not applicable.
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 26.23. The other information required by Item 10 is incorporated herein by reference to the captions "Nominees For Directors,"NOMINEES FOR DIRECTORS," "Continuing Directors,"CONTINUING DIRECTORS," "Board Meetings -Committees of the Board,"BOARD MEETINGS -COMMITTEES OF THE BOARD," "Governance Information"GOVERNANCE INFORMATION - SCANA's Code of Conduct & Ethics" and "Other Information-Section"OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy statement for the 20062007 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 Codecode of Ethicsethics 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"Company Profile - Codecode of Conduct & Ethics"conduct" 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)April 27, 2006 to hold office until the next annual meeting of SCE&G's shareholders to be held on April 27, 2006.26, 2007. Each of the directors is also a director of SCANA. There are no family relationships among any of SCE&G's directors and executive officers.
| Name and Year FirstWilliam C. Burkhardt (Age 69)*
Became Director since 2000
| | |
| | | |
| Mr. Burkhardt has served as Chairman and Chief Executive Officer of Titan Holdings, LLC, a real estate investment company, located in Raleigh, North Carolina, since May 2004. He was Chief Executive Officer of Capital Bank, in Raleigh, North Carolina, from October 2003 until retiring in May 2004. From May 2000 until October 2003, Mr. Burkhardt pursued personal interests. Mr. Burkhardt retired as President and Chief Executive Officer of Austin Quality Foods, Inc., a production and distribution company of baked snacks for the food industry, located in Cary, North Carolina, in May 2000, having served in that position since 1980. Mr. Burkhardt is a director of Capital Bank, in Raleigh, North Carolina and Plaza Belmont II, in Kansas City, Missouri. | |
| | | |
| W. Hayne Hipp (Age 66) AgeDirector since 1983
| Principal Occupation; Directorships
| |
Bill L. Amick
(1990)
| 62 | For
|
| Mr. Hipp is a private investor. Prior to its acquisition in January 2006, Mr. Hipp was Chairman, Chief Executive Officer and a director of The Liberty Corporation, a broadcasting holding company headquartered in Greenville, South Carolina. He held these positions for more than five years,years. | |
| | | |
| Harold C. Stowe (Age 60)* Director since 1999 | | |
| | |
| Mr. Stowe has been acting Dean of the Wall College of Business at Coastal Carolina University in Conway, South Carolina since June 1, 2006. Mr. Stowe retired in February, 2005 as President of Canal Holdings, LLC, a forest products industry company, located in Conway, South Carolina. Prior to his retirement, Mr. Stowe had served as President of Canal Holdings, LLC, and its predecessor company since March 1997. Mr. Stowe is a director of Ruddick Corporation, in Charlotte, North Carolina. | |
| | | |
| G. Smedes York (Age 66) Director since 2000 | | |
| | |
| Mr. York is Chairman and Treasurer of York Properties, Inc., a full-service commercial and residential real estate company, in Raleigh, North Carolina. Mr. York has been associated with York Properties, Inc. since 1970. Mr. York also is Chairman of the Board of York Simpson Underwood, a residential brokerage company, and of McDonald-York, Inc., a general contractor, both in Raleigh, North Carolina. | |
| Bill L. Amick (Age 63) Director since 1990 | | |
| | |
| Mr. Amick is the Chairman of The Amick Company, a real estate development company that develops residential and resort properties. On October 30, 2006, Mr. Amick retired from Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., Batesburg, SC (verticallya vertically integrated broiler operation)operation. Prior to his retirement, he served as Chairman of the Board of the Amick entities all of which are located in Batesburg, South Carolina. He held those positions for more than five years. Mr. |
| | Director, SCANA Corporation; PSNC Energy;Amick is a director of 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,Sharon A. Decker (Age 49)
Director since 2005 | | |
| | |
| Mrs. Decker is the founder and has been the principal of The Tapestry Group LLC, a faith based consulting and communications company, located in Rutherfordton, North Carolina, since September 2004. Mrs. Decker previously served as president of Tanner Holdings LLC and Doncaster, apparel manufacturers, from August 1999 until September 2004. Mrs. Decker is a director of Coca-Cola Bottling Company Consolidated, Inc. and Family Dollar Stores, Inc., both in Charlotte, North Carolina. | |
| | | |
| D. Maybank Hagood (Age 45)* Director since 1999 | | |
| | |
| Mr. Hagood has been President and Chief Executive Officer of Southern Diversified Distributors, Inc., a provider of logistic and distribution services, located in Charleston, South Carolina, 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 2003since November, 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.
|
D. Maybank Hagood*
(1999)
| 44 | For more than five years,Hagood also has been President and Chief Executive Officer of William M. Bird and Company, Inc. (wholesale, a subsidiary of Southern Diversified Distributors, Inc., a wholesale distributor of floor covering materials) and its subsidiary Southern Diversified Distributors, LLC, (provider of logistics services) bothmaterials, in Charleston, SC.
South Carolina, since 1993. | |
| | | Director, SCANA Corporation; PSNC Energy.
| |
| W. Hayne HippWilliam B. Timmerman (Age 60)
(1983)Director since 1991
| 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.
|
| Mr. Timmerman has been Chairman of the Board and Chief Executive Officer of SCANA since March 1, 1997. He has been President of SCANA since December 13, 1995. | |
| James A. Bennett (Age 45) Director since 1997 | | |
| | |
| Mr. Bennett has been Executive Vice President and Director of Public Affairs of First Citizens Bank, located in Columbia, South Carolina, since August 2002. Previously, he was President and Chief Executive Officer of South Carolina Community Bank, in Columbia, South Carolina, from May 2000 to July 2002. | |
| | | |
| Lynne M. Miller*Miller (Age 55) (1997)Director since 1997
| 54 | Since August 2005, Senior Business Consultant to
|
| | |
| Ms. Miller has been an environmental consultant since her retirement from Quanta Capital Holdings, Inc., Reston, VA (aa specialty insurer). |
| | insurer, in August 2006. From August 2005 to August 2006 she was a Senior Business Consultant at Quanta Capital Holdings. From April 2004 through July 2005, she was President of Quanta Technical Services LLC., Reston VA. |
| | From September 2003 through March 2004, She was Chief Executive Officer of Environmental Strategies Consulting LLC, a division of Quanta Technical Services LLC.LLC, from September 2003 through March 2004. Ms. Miller co-founded Environmental Strategies Corporation, (anan environmental consulting firm)firm in Reston, Virginia, in 1986, and served as President from 1986 until 1995 and as Chief Executive Officer from 1995 until September 2003 when the firm was acquired by Quanta Capital Holdings, Inc. and its name was changed to Environmental Strategies Consulting LLC.
|
| | Director, SCANA Corporation; PSNC Energy; Ms. Miller is a director of Adams National Bank, (aa subsidiary of Abigail Adams National Bancorp, Inc.), in Washington, DC.
D.C. | |
| | | |
| Maceo K. Sloan*Sloan (Age 57)* (1997)Director since 1997
| 56 | |
| | |
| For more than five years,Mr. Sloan is Chairman, President and ChiefExecutiveOfficer of Sloan Financial Group, Inc. (financial, a financial holding company)company, and Chairman, Chief Executive Officer and Chief Investment Officer of both NCM Capital Management Group, Inc., and NCM Capital Advisers, Inc. (investment, investment management companies),companies, in Durham, NC.
|
| | Director, SCANA Corporation; PSNC Energy; M&F Bancorp, Inc. and its subsidiary, Mechanics and Farmers Bank; and TrusteeNorth Carolina. He has held these positions for more than five years. Mr. Sloan is a trustee of Teachers Insurance Annuity Association-College Retirement Equity Fund 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).Funds Boards, Chairman of the Board of
York Simpson Underwood (residential brokerage company) M&F Bancorp, Inc. and McDonald-York, Inc. (general contractor) botha director of its subsidiary, Mechanics and Farmers Bank, in Raleigh, NC.Durham, North Carolina.
|
| | Director, SCANA Corporation; PSNC Energy.
|
*Indicates a member of the Audit Committee of SCE&G's&G’s Board of Directors. Mr. Stowe has been determined by SCE&G's&G’s board of directors to be an audit committee financial expert within the meaning of Item 401(h)407(d)(5) of Regulation S-K. SCE&G's&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 underdefined by the New York Stock Exchange Act.Listing Standards.
EXECUTIVE OFFICERS
SCE&G's officers are elected at the annual organizational meeting of the Board of Directors and hold office until the next such organizational meeting, unless (1) a resignation is submitted, (2) the Board of Directors shall otherwise determine, or unless a resignation is submitted.(3) as provided in the By-laws of SCE&G.
Name | Age | Positions Held During Past Five Years | Dates |
| W. B. Timmerman | 5960 | Chairman of the Board and Chief Executive Officer | *-present |
| J. E. Addison | 46 | Senior Vice President and Chief Financial Officer Vice President - Finance | 2006-present *-2006 |
| J. C. Bouknight | 5354 | Senior Vice President-Human Resources Vice President Human Resources-Dan River, Inc.-Danville, VA | 2004-present *-2004 |
| S. D. Burch | 4849 | Senior Vice President, Fuel Procurement and Asset Management Deputy General Counsel and Assistant Secretary | 2003-present *-2003 |
| S. A. Byrne | 4647 | Senior Vice President-Generation, Nuclear and Fossil Hydro Senior Vice President-Nuclear Operations | 2004-present *-2004 |
| P. V. Fant | 5253 | Senior Vice President TransmissionPresident-Transmission Services President and Chief Operating Officer-SCPCOfficer-CGTC (formerly SCPC and SCG PipelineSCG) Executive Vice President-SCPC Executive Vice President-SCG and SCG Pipeline Inc.
| 2004-present 2004-present *-2004 2002-2004
|
N. O. LorickK. B. Marsh | 5551 | President and Chief Operating Officer | *-present |
K. B. Marsh | 50 | Senior Vice President and Chief Financial Officer Controller President and Chief Operating Officer-PSNC Energy | 2006-present *-present-2006 *-2003 |
| F. P. Mood, Jr. | 6869 | 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, 20012002
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 theits 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 2005.2006.
SCANA: The information called forrequired by Item 11 Executive Compensation, is incorporated herein by reference to the captions "Director Compensation,"EXECUTIVE COMPENSATION," "Compensation Committee Interlocks and Insider Participation,"COMPENSATION COMMITTEE REPORT," "SUMMARY COMPENSATION TABLE," "2006 GRANTS OF PLAN-BASED AWARDS," "OUTSTANDING EQUITY AWARDS AT 2006 FISCAL YEAR END," "2006 OPTION EXERCISES AND STOCK VESTED," "PENSION BENEFITS," "2006 NONQUALIFIED DEFERRED COMPENSATION," "POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL," and "Executive Compensation"“DIRECTOR COMPENSATION” in SCANA's definitive proxy statement for the 20062007 annual meeting of shareholders.
SCE&G: The information required by Item 11 is as follows:
EXECUTIVE COMPENSATION
Compensation Committee Processes and Procedures
SCANA's Human Resources Committee, which is comprised entirely of independent directors, administers the senior executive compensation program for SCANA and all of its subsidiaries, including SCE&G. Compensation decisions for all senior executive officers and directors are approved by the Human Resources Committee and recommended by the Committee to the full Board for final approval. The Committee considers recommendations from our Chairman and Chief Executive Officer in setting compensation for senior executive officers and directors.
In addition to attendance by members of the Human Resources Committee, the Committee’s meetings are also regularly attended by our Chairman and Chief Executive Officer and our Senior Vice President of Human Resources. However, at each meeting the Committee also meets in executive session. The Chairman of the Committee reports the Committee’s recommendations on executive compensation to the Board of Directors. Our Human Resources and Tax Departments support the Human Resources Committee in its duties, and the Committee may delegate authority to these departments to fulfill administrative duties relating to our compensation programs.
Under its charter, the Committee has the authority to retain, approve fees for, and terminate advisors, consultants and others as it deems appropriate to assist in the fulfillment of its responsibilities. The Committee has, however, historically chosen to use relevant information provided to us by management’s consultant, Hewitt Associates. The Committee uses this information to assist it in carrying out its responsibilities for overseeing matters relating to compensation plans and compensation of our senior executive officers. Using information provided by a national compensation consultant helps to assure the Committee that our policies for compensation and benefits are competitive and aligned with utility and general industry practices.
Compensation Discussion and Analysis
Objectives and Philosophy of Executive Compensation
The senior executive compensation program is designed to support our overall objective of increasing shareholder value by:
| · | Hiring and retaining premier executive talent; |
| · | Having a pay-for-performance philosophy that links total rewards to achievement of corporate, business unit and individual goals, and places a substantial portion of pay for senior executives "at-risk"; |
| · | Aligning the interests of executives with the long-term interests of shareholders through long-term equity-based incentive compensation; and |
| · | Relating the elements of the compensation program to focus on the proper balance of financial, customer-service, operational and strategic goals. |
We have designed our compensation program to reward senior executive officers for their individual and collective performance, and for our collective performance in achieving target goals for earnings per share and total shareholder return and other annual business objectives. We believe our program performs a vital role in keeping executives focused on improving our performance and enhancing shareholder value while rewarding successful individual executive performance in a way that helps to assure retention.
The following discussion provides an overview of our compensation program for all of our senior executive officers (a group of approximately ten people who are at the level of senior vice president and above), as well as a specific discussion of compensation for our Chief Executive Officer, our Chief Financial Officer and the other executive officers named in the Summary Compensation Table that follows this “Compensation Discussion and Analysis.” In this discussion, we refer to the executives named in the Summary Compensation Table as “Named Executive Officers.”
Principal Components of Executive Compensation
During 2006, senior executive compensation consisted primarily of three key components: base salary, short-term cash incentive compensation (under the Short-Term Annual Incentive Plan) and long-term equity-based incentive compensation (under the SCANA shareholder approved Long-Term Equity Compensation Plan). We also provide various additional benefits to senior executive officers, including health, life and disability insurance plans, retirement plans, termination, severance and change in control arrangements, and perquisites. The Human Resources Committee makes its decisions about how to allocate senior executive officer compensation among base salary, short-term cash incentive compensation and long-term equity-based incentive compensation on the basis of information provided by our compensation consultant, and our goals of remaining competitive with the compensation practices of a group of surveyed companies and of linking compensation to our corporate performance and individual senior executive officer performance.
A more detailed discussion of each of these components of senior executive officer compensation, the reasons for awarding such types of compensation, the considerations in setting the amounts of each component of compensation, the amounts actually awarded for the periods indicated, and various other related matters is set forth in the sections below.
SCANA sponsors the Short-Term Annual Incentive Plan and the Long-Term Equity Compensation Plan which are available to eligible senior executive officers of SCE&G. These plans are referred to herein as "our" plans.
Factors Considered in Setting Senior Executive Officer Compensation
Use of Market Surveys and Peer Group Data
We believe it is important to consider comparative market information about compensation paid to executive officers of other companies in order to remain competitive in the executive workforce marketplace. We want to be able to attract and retain highly skilled and talented senior executive officers who have the ability to carry out our short-and long-term goals. To do so, we must be able to compensate them at levels that are competitive with compensation offered by other companies in our business or geographic marketplace that seek similarly skilled and talented executives. Accordingly, we consider market survey results in establishing target compensation levels for all components of compensation. The market survey information is provided to us every other year by our compensation consultant. In years in which our consultant does not provide us with market survey information, our current process is to apply an aging factor to the prior year’s information with assistance from our consultant based on its experience in the marketplace. Our most recent surveys were performed in 2005.
Our goal is to set base salary and long-and short-term incentive compensation for our senior executive officers at the median (50th percentile) of compensation paid for similar positions by the companies included in the market surveys.We set our target at the median because we believe this target will meet the requirements of most of the persons we seek to hire and retain in our geographic area, and because we believe it is fair both to us and to the executives. Variations to this objective may, however, occur as dictated by the experience level of the individual, internal equity and market factors. We do not set a target level for broad-based benefits for our senior executive officers, but our market survey information indicates that they currently are approximately at the median.
The companies included in the market surveys are a group of utilities and general industry companies of various sizes in terms of revenue. Approximately half of the companies included in the most recent market surveys had substantially the same levels of annual revenues as we had, while the remainder had revenues not greater than four times our revenues. Market survey results for each position are adjusted using regression analysis to account for these differences in company revenues. To a large extent, the companies included in the survey results were those that had agreed to participate in market surveys included in our compensation consultant’s database.
The companies included in the market survey we used in connection with setting base salaries and short-term incentive compensation for 2006, and the states in which they are headquartered are listed below:
Utility Industry: AGL Resources, Inc. (GA); Ameren Corporation (MO); Aquila, Inc. (MO); Black Hills Corporation (SD); CenterPoint Energy (TX); Cinergy Corp. (OH); Cleco Corporation (LA); CMS Energy Corporation (MI); Dominion Resources, Inc. (VA); DTE Energy Company (MI); Duke Energy Corporation (NC); Edison International (CA); El Paso Electric Company (TX); FPL Group, Inc. (FL); Great Plains Energy (MO); Nicor Inc. (IL); NiSource Inc. (IN); Pepco Holdings, Inc. (DC); PNM Resources, Inc. (NM); PPL Corporation (PA); Progress Energy, Inc. (NC); Public Service Enterprise Group (NJ); Sempra Energy (CA); Southern Company (GA); WGL Holdings, Inc. (DC).
General Industry: Alliant Techsystems Inc. (MN); ALLTEL Corporation (AR); Armstrong World Industries (PA); Ball Corporation (CO); Becton Dickinson and Co. (NJ); BorgWarner Inc. (MI); Brunswick Corporation (IL); C.R. Bard, Inc. (NJ); The Clorox Company (CA); Cooper Cameron Corp. (TX); Cooper Industries (TX); Ecolab Inc. (MN); FMC Corporation (PA); Hasbro, Inc. (RI); MeadWestvaco Corporation (VA); Medtronic, Inc. (MN); Packaging Corp. of America (IL); Praxair, Inc. (CT); The Sherwin-Williams Co. (OH); Sonoco Products Company (SC); Springs Industries, Inc. (SC); Steelcase Inc. (MI); Wm. Wrigley Jr. Company (IL).
We believe the utilities included in our market surveys are an appropriate group to use for compensation comparisons because they align well with our sales and revenues, the nature of our business and workforce, and the talent and skills required for safe and successful operations. We believe the additional non-utility companies included in our market surveys are appropriate to include in our comparisons because they align well with our sales and revenues, and are the types of companies that might be expected to seek executives with the same general skills and talents as the executives we are trying to attract and retain in our geographic area. The companies we use for comparisons may change from time to time based on the factors discussed above.
To make comparisons with the market survey results, we generally divide all of our senior executive officers into utility and non-utility executive groups - that is, executive officers whose responsibilities are primarily related to utility businesses and require a high degree of technical or industry-specific knowledge (such as electrical engineering, nuclear engineering or gas pipeline transmission), and those whose responsibilities are more general and do not require such specialized knowledge (such as marketing, business and other corporate support functions). We then attempt to match to the greatest degree possible our positions with similar positions in the survey results. For positions that do not fall specifically into the utility or non-utility group, we may blend the survey results to achieve what we believe is an appropriate comparison.
We also use performance data covering a larger peer group of companies in determining long-term equity incentive compensation under the SCANA shareholder approved long-term equity compensation plan, as discussed below under “Long-Term Equity Compensation Plan.”
Personal Qualifications
In addition to considering market survey comparisons, we consider each senior executive officer’s knowledge, skills, scope of authority and responsibilities, job performance and tenure with us as a senior executive officer.
Mr. Timmerman has been our Chief Executive Officer for 10 years, and has been employed with us in various capacities, including Chief Financial Officer and Chief Operating Officer, for over 28 years. Mr. Timmerman started his career as a certified public accountant. As our Chief Executive Officer, Mr. Timmerman has responsibility for strategic planning, development of our senior executive officers and oversight of all our operations.
Mr. Addison was appointed our Senior Vice President and Chief Financial Officer in April 2006, prior to which he had served as Vice President-Finance since 2001. As Chief Financial Officer, he is responsible for all of our financial operations, including accounting, risk management, treasury, investor relations, shareholder services, taxation and financial planning, as well as our information technology functions. Mr. Addison is a certified public accountant, and has been with us for over 15 years.
Mr. Marsh was appointed President and Chief Operating Officer of South Carolina Electric & Gas Company in April 2006, prior to which he had served as Senior Vice President-Finance and Chief Financial Officer since 1998. As President of SCE&G, he is responsible for all of its gas and electric operations, as well as for all of our facilities and properties management. Mr. Marsh previously practiced as a certified public accountant and has been with us for over 22 years.
Mr. Mood is Senior Vice President and General Counsel. In these positions, he is responsible for overseeing our legal activities as well as our Legal, Environmental and Corporate Secretary’s Departments. Mr. Mood has been with us for two years. Prior to his employment with us, Mr. Mood was in private practice as a lawyer for 37 years. Mr. Mood has previously served as Interim Dean of The University of South Carolina School of Law and as chairman of the South Carolina Board of Law Examiners, and is a permanent member of the Judicial Conference of the United States Court of Appeals for the Fourth Circuit.
Mr. Bouknight has been with us for two years. He is Senior Vice President - Human Resources. In this position, he is responsible for all human resources functions, corporate security, claims and aviation. Mr. Bouknight has over 28 years experience as a human resources professional.
Mr. Byrne is Senior Vice President-Generation, Nuclear and Fossil Hydro. In these positions, he is responsible for overseeing all of our activities related to nuclear power, including nuclear plant operations, core analysis, emergency planning, licensing and nuclear support services. He has been with us for 11 years, and has over 20 years experience in the nuclear industry.
Other Factors Considered
In addition to the foregoing information, we consider the fairness of the compensation paid to each senior executive officer in relation to what we pay our other senior executive officers. The Human Resources Committee also considers recommendations from our Chairman and Chief Executive Officer in setting compensation for senior executive officers. We also consider the senior executive’s level of ownership of SCANA's common stock in relationship to the senior executive’s tenure and salary level.
We review our compensation program and levels of compensation paid to all of our senior executive officers, including the Named Executive Officers, annually and make adjustments based on the foregoing factors as well as other subjective factors.
In 2006, the Human Resources Committee reviewed summaries of compensation components (“tally sheets”) for all of our senior executive officers, including the Named Executive Officers. These tally sheets reflected changes in compensation from the prior year and affixed dollar amounts to each component of compensation. The Committee intends to use such tally sheets in the future to review each component of the total compensation package, including base salaries, short-and long-term incentives, severance plans, and insurance, retirement and other benefits, in determining the total compensation package for each senior executive officer.
Timing of Senior Executive Officer Compensation Decisions
Annual salary reviews and adjustments and short-term and long-term incentive compensation awards are routinely made in February of each year at the first regularly scheduled Human Resources Committee and Board meeting. Determinations also are made at that meeting as to whether to pay out awards under the most recently completed three-year cycle of long-term equity-based incentive compensation. Compensation determinations also may be made by the Committee at its other quarterly meetings in the case of newly hired executives or promotions of existing employees that could not be deferred until the February meeting. We routinely make our annual and quarterly earnings releases in conjunction with the quarterly meetings of our Board.
Base Salaries
Senior executive officer base salaries are divided into grade levels based on market data for similar positions and experience. The Human Resources Committee believes it is appropriate to set base salaries at a reasonable level that will provide executives with a predictable income base on which to structure their personal budgets. Accordingly, base salaries are targeted at the median (50th percentile) of the survey data. The Human Resources Committee reviews base salaries annually and makes adjustments on the basis of an assessment of individual performance, relative levels of accountability, prior experience, breadth and depth of knowledge, changes in market compensation practices as reflected in market survey data, and relative compensation levels within our company.
With the exception of the base salaries of Mr. Addison and Mr. Marsh, the Committee did not increase base salaries for the Named Executive Officers in 2006 based on its determination that current salaries were appropriate in light of the market survey data and relative compensation levels within our company. The Committee increased Mr. Addison’s base salary as a result of his promotion to Senior Vice President and Chief Financial Officer, and increased Mr. Marsh’s base salary as a result of his transition to President and Chief Operating Officer of SCE&G. In making the decisions with respect to the increases in base salaries for Messrs. Addison and Marsh, and the decision not to increase base salaries of the other Named Executive Officers, the Committee took into consideration recommendations of our Chief Executive Officer.
Short-Term and Long-Term Incentive Compensation
Our senior executive officer compensation program provides for both short-term incentive compensation in the form of annual cash incentive compensation, and long-term equity-based incentive compensation payable at the end of cycles which have historically lasted three years. Both our short-term and long-term executive incentive compensation plans promote our pay-for-performance philosophy, as well as our goal of having a meaningful amount of pay "at-risk", and we believe both plans provide us a competitive advantage in recruiting and retaining top quality talent.
We believe the short-term incentive compensation plan provides our senior executive officers with an annual stimulus to achieve short-term individual and business unit or departmental goals and short-term corporate earnings goals that ultimately help us achieve our long-term corporate goals. We believe the long-term equity-based incentive compensation counterbalances the emphasis of short-term incentive compensation on short-term results by focusing our senior executive officers on success of our long-term corporate goals; provides additional incentives for them to remain our employees by ensuring that they have a continuing stake in the long-term success of the Company; and helps to align the interests of senior executive officers with those of shareholders.
SCE&G: Short-Term Annual Incentive Plan
The information calledShort-Term Annual Incentive Plan provides financial incentives for performance in the form of opportunities for annual incentive cash payments. Participants in the Short-Term Annual Incentive Plan include not only senior executive officers, but also approximately 183 additional employees, including other officers, senior management, division heads and other professionals whose positions or levels of responsibility make their participation in the plan appropriate. Our Chief Executive Officer recommends, and the Human Resources Committee approves, the performance measures, operational goals and other terms and conditions of incentive awards for executives, including the Named Executive Officers.
The Committee reviews and approves target short-term incentive levels at its first regularly scheduled meeting each year based on percentages assigned to each executive salary grade. Actual short-term incentive awards are based both on the Company’s meeting pre-determined financial and business objectives, and on each senior executive officer’s level of performance as compared to his or her individual financial and strategic objectives. In assessing accomplishment of objectives, the Committee considers the difficulty of achieving each objective, unforeseen obstacles or favorable circumstances that might have altered the level of difficulty in achieving the objective, overall importance of the objective to our long-term and short-term goals, and importance of achieving the objective to enhancing shareholder value. Changes in annual target short-term incentive levels can be made if there are changes in the senior executive officer’s salary grade level that warrant a target change.
The plan allows for an increase or decrease in short-term incentive award payout of up to 20% of the target award based on an individual’s performance in meeting individual financial and strategic objectives. The plan also allows for an increase or decrease in award payout of up to 50% of the target award based on the extent to which we achieve our pre-determined financial objectives. However, cumulative adjustments to target award payouts for all participants may not increase or decrease overall award levels by Item 11,more than 50%. Individual awards may nonetheless be decreased or eliminated if the Human Resources Committee determines that actual results warrant a lower payout.
For each Named Executive Officer, except Mr. Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis on the following financial and business objectives for 2006:
| · | Achieving earnings per share targets which were set to reflect SCANA’s published earnings per share growth guidance; and |
| · | Achieving annual business objectives relating to our four critical success factors: cost effective operations, profitable growth, excellence in customer service, and developing our people. |
For Mr. Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis in 2006 on achieving the earnings per share targets and performance of our senior executive officers.
The specific objectives for each senior executive officer are weighted according to the extent to which the executive will be responsible for results of the objectives. The weightings assigned to the business objectives for each Named Executive Officer for 2006 are shown in the table below:
2006 Weightings Assigned to Each Business Performance Objective
for Named Executive Officers
| Objective | Mr. Timmerman | Mr. Marsh | Mr. Addison | Mr. Mood, Jr. | Mr. Bouknight | Mr. Byrne |
| Senior Staff Performance | 50% | | | | | |
| Financial Results | 50% | 50% | 50% | 50% | 50% | 50% |
| Cost Effective Operations | | 20% | 30% | | 10% | 40% |
| Profitable Growth | | 10% | 10% | | 10% | |
| Customer Service | | 10% | 10% | 37.5% | 10% | 10% |
| Developing our People | | 10% | | 12.5% | 20% | |
SCANA did not achieve earnings per share targets for 2006 and, accordingly, we did not make any earnings per share-related payouts under the Short-Term Annual Incentive Plan. However, we achieved our business objectives and our senior executive officers achieved their individual financial and strategic objectives. Accordingly, we made payouts to our senior executive officers, including our Named Executive Officers, with respect to the business and individual financial and strategic objectives portions of the plan. As further discussed below under the caption “- - Discretionary Bonus Award,” we also made a 20% discretionary bonus award to each of our senior executives officers, including our Named Executive Officers as permitted by the plan. The 2006 Short-Term Incentive Plan awards based on our achieving our business objectives and our Named Executive Officer's achieving their individual objectives are reflected in the Summary Compensation Table under the column “Non-Equity Incentive Plan Compensation,” and the discretionary bonus award under the plan is reflected in the Summary Compensation Table under the column “Bonus.”
Individual Financial and Strategic Objectives on which 2006 Short-Term Annual Incentive Awards were Based
The individual financial and strategic objectives the Human Resources Committee considered in determining short-term incentive awards for the Named Executive Officers were as follows:
Mr. Timmerman’s award was based on his contributions and his leadership of other senior executives in achieving our overall corporate strategic plan objectives. For 2006, our strategic objectives, which were included in business unit objectives, were leveraging employee and business development; ensuring the security of our people, assets and operations; optimizing the use of our utility assets; effectively addressing new environmental, regulatory and legislative issues; and effectively managing fuel and healthcare costs.
Mr. Addison’s award was based on his successful efforts toward maintaining financial reporting compliance processes and procedures that meet the requirements of the Sarbanes-Oxley Act; his analysis and documentation relating to electric and gas regulatory decisions for 2006; his oversight of the successful implementation of transition of certain information technology systems and system testing; and progress toward development of a plan relating to insurance coverage for catastrophic property loss risks.
Mr. Marsh’s award was based on his progress toward developing plans to enhance our succession strategy; progress toward developing, obtaining approval of, and preparing for implementation of, a cost effective and responsible environmental strategy; oversight of efforts to optimize the allocation of natural gas assets and implementation of the transition to open access; identification and tracking of compliance with existing and emerging regulations; and effectiveness in managing the operation and maintenance and capital budgets.
Mr. Mood’s award was based on his effective oversight of implementation of annual internal reporting and assessments relating to environmental issues; fostering collaborative relationships between our legal department and our business units; effective oversight of training relating to Federal Energy Regulatory Commission regulations; and effective oversight of the legal, environmental, and corporate secretary departments’ staffing and management.
Mr. Bouknight’s award was based on his successful oversight of the development and implementation of a succession and leadership development program; progress toward improved interaction between the Human Resources department and its constituencies; successful oversight of completion of a company-wide Human Resources department website; and successful oversight of programs focused on employee health and wellness.
Mr. Byrne’s award was based on his oversight of our achieving a system availability factor beyond targeted levels for our fossil hydro operations; the fact that our fossil hydro operations demonstrated environmental responsibility; oversight of successful implementation of certain system modifications during refueling at our nuclear plant; oversight of a very successful refueling outage; and oversight of progress toward licensing, site selection, vendor selection and project development agreement for a potential new nuclear plant.
Discretionary Bonus Award
The 20% discretionary bonus awards were recommended to the Human Resources Committee by our Chief Executive Officer, and both the Human Resources Committee and the Board approved the discretionary payout. The bases for the discretionary portion of the award are as follows:
| · | Two primary factors that held down financial performance (mild weather and loss of industrial customers) were not within the control of our employees; |
| · | Our management team has made tremendous progress this year dealing with long-term strategic issues, such as planning for future expansion of generation, coping with pending environmental challenges, and dealing with a host of federal regulatory changes that are both complex and often not well defined; and |
| · | There were a number of exceptional short term accomplishments in the past year, including having three of our coal fired plants rated among the 20 most efficient plants in the United States. |
We believe this discretionary payment to our short-term bonus plan participants is well-justified and necessary to reward and retain our critical human resources.
SummaryLong-Term Equity Compensation TablePlan
| | | 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 underThe potential value of long-term equity-based incentive opportunities comprises a significant portion of the Annual Incentive Plan.total compensation package for senior executive officers and key employees. The Human Resources Committee believes this approach to total compensation provides the appropriate long-range focus for senior executive officers and other key employees who are charged with responsibility for managing the Company and achieving success for shareholders because it links the amount of their compensation to our business and financial performance.
(2)PayoutsA portion of performance shareeach senior executive officer's potential compensation consists of 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 The types of long-term equity-based compensation the Human Resources Committee may award under the plan include incentive and nonqualified stock options, stock appreciation rights (either alone or in 2005. Base salarytandem with a related stock option), restricted stock, performance units and performance shares. In recent years, the only long-term equity-based awards have been in the form of $1,002,700 became effective on February 17, 2005.
Option Exercises, Outstanding Options and Related Information
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
(a) | (b) | (c) | (d) | (e) |
| | | | Number of Securities Underlying Unexercised Option/SARs At FY-End (#) | Value of Unexercised In-the-Money Options/ SARs at FY-End ($)(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 betweenspecific performance goals. For 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 the2006-2008 performance shareperiod, awards made in 2005 (for potential payment in 2008) under the Long-Term Equity Compensation Plan consisted solely of performance shares. We have not awarded stock options since 2002 and estimated future payouts under that plan at threshold, target and maximum levels for each of the executive officers includedhave no plans to do so in the Summaryforeseeable future.
Payouts of awards under the Long-Term Equity Compensation Table.Plan may be made in cash or SCANA common stock at our discretion, but are most frequently made in cash. We believe awards of performance units and performance shares align the interests of our executives with those of shareholders because the value of such awards is tied to our achieving financial and business goals that would be expected to affect the value of SCANA's common stock.
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.Performance Share Awards
Sixty percent of targetFor the 2005-2007 and 2006-2008 plan cycles, performance share awards areto senior executive officers under the Long-Term Equity Compensation Plan were based on SCANA’s total shareholder return (“TSR”(1) SCANA's Total Shareholder Return ("TSR") relative to the TSR of a group of peer companies over the three-year plan cycle comparedperiods and (2) a three-year average growth in earnings component based on SCANA's earnings per share under generally accepted accounting principles, with a peer group. adjustments to be made to account for the cumulative effects of any mandated changes in accounting principles and the effects of any sales of certain investments or impairment charges related to certain investments (we refer to this component as growth in “EPS from ongoing operations”).
TSR is calculated by dividing stock price increase over the three-year period,periods is equal to the change in SCANA's common stock price, plus cash dividends paid on SCANA's common stock during the period, divided by theSCANA's common stock price as of the beginning of the period.
Performance share awards place a portion of executive compensation at risk because executives are compensated pursuant to the awards only when the objectives for TSR and earnings growth are met. Additionally, comparing TSR to the TSR of a group of other companies reflects our recognition that investors could have invested their funds in other entities, and measures how well we performed over time when compared to others in the group.
Creating a new three-year cycle each year provides an opportunity to adjust the target, threshold and maximum award levels based on historical performance, and provides an ongoing long-term incentive to senior executive officers. Payouts varyunder the 2005-2007 and 2006-2008 cycles will be based upon the extent to which SCANA meets its performance goals for the entire three-year periods.
Beginning with the 2007-2009 plan cycle, however, the Long-Term Equity Compensation Plan provides for performance measurement and award determination on an annual basis (rather than the above described three-year measurement and determination), with payment of awards being deferred until after the end of the three-year performance cycle. Accordingly, payouts under the 2007-2009 plan cycle will be earned for each year that performance goals are met during the three-year cycle, though payments will be deferred until the end of the cycle and will be contingent upon the participant’s still being employed by us at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability. Additionally, the payment of the EPS growth component of the 2007-2009 plan cycle awards will be based on growth in “GAAP-adjusted net earnings per share from operations” as that term is used in SCANA’s periodic reports and external communications. GAAP-adjusted net earnings per share from operations may reflect different or additional adjustments than are or would have been reflected in the determination of EPS from ongoing operations in prior plan cycles. We believe that these changes for the 2007-2009 cycle will increase the effectiveness of the plan in encouraging executive retention by minimizing the impact of extraordinarily strong or poor single-year performance on award payouts. The other performance criteria adopted by the Board on recommendation of the Human Resources Committee for the 2007-2009 plan cycle do not differ materially from the 2006-2008 plan cycle.
2006 Long-Term Incentive Plan Awards
In 2006, we made performance share awards to each of the Named Executive Officers. The awards have a three-year cycle ending in 2008 and are payable based on SCANA levels of performance against pre-determined measures of TSR and average growth in EPS from ongoing operations over the three-year plan cycle. Information about the performance criteria for the 2006-2008 cycle is set forth below. Information about the number of performance shares awarded for the 2006-2008 cycle is provided in the “2006 Grants of Plan-Based Awards” table.
Sixty percent of the 2006 target performance share awards are based on SCANA's TSR over the three-year plan cycle compared with the peer group of utilities set forth below:
Allegheny Energy, Inc.; Allete Inc.; Alliant Energy Corporation; Ameren Corporation; Avista Corporation; Cinergy Corp.; Cleco Corporation; CMS Energy Corporation; Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources, Inc.; DPL, Inc.; DTE Energy Company; Duquesne Light Holdings, Inc.; Edison International; Energy East Corporation; Entergy Corporation; FirstEnergy Corp.; FPL Group, Inc.; Great Plains Energy, Inc.; Hawaiian Electric Industries, Inc.; IDACORP, Inc.; NiSource Inc.; Northeast Utilities; NorthWestern Corporation; NSTAR; OGE Energy Corp.; Pepco Holdings, Inc.; Pinnacle West Capital Corporation; PNM Resources, Inc.; PPL Corporation; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; Puget Energy, Inc.; Sierra Pacific Resources; Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UniSource Energy Corporation; Vectren Corporation; Westar Energy, Inc.; Wisconsin Energy Corporation; WPS Resources Corporation.
The number of utilities included in the peer group used for TSR comparisons is larger than the number included in the market survey utility peer group we use for purposes of setting base salary and short-term incentive compensation because information about TSR is publicly available for a larger number of utilities. We include only utilities in the TSR peer group because we have assumed that shareholders would measure SCANA's performance against performance of other utilities in which they might have invested.
Payouts based on the TSR component of the plan are scaled according to SCANA’sSCANA's ranking against the peer group. No payout is earned if performance is less than the 33rd33rd percentile. ExecutivesSenior executive officers earn threshold payouts (50%(equal to 50% of target award) if SCANA ranks at the 33rd33rd percentile in relation to the peer group’sgroup's three-year TSR performance. Target payouts (100%(equal to 100% of target award) occur if SCANA ranks at the 50th50th percentile in relation to the peer group’sgroup's three-year TSR performance. Maximum payouts (150%(equal to 150% of target award) result if SCANA’s performance ranks at or above the 75th75th percentile in relation to the peer group’sgroup's three-year TSR performance. Payouts are scaled between 50% and 150% based on the actual percentile achieved. No payouts may exceed 150% of the target award. Threshold, target and maximum payouts at the 33rd, 50th and 75th percentiles were used because these match generally the levels used by the companies in the market survey data.
Forty percent of the 2006 performance share awards were based on meeting SCANA's projections for three-year average growth in EPS from ongoing operations. Payouts for target performance share awards granted in 2006 for the 2006-2008 performance period will be made if three-year average growth in EPS from ongoing operations equals 3.7%. Executives would earn threshold payouts (equal to 50% of target award) at 1.7% average growth, target payouts (equal to 100% of target award) at 3.7% average growth, and maximum payouts (equal to 150% of target award) at or above 5.7% average growth. Payouts are scaled between 50% and 150% based on meeting SCANA’s goals for three-yearthe actual growth in earnings per share (“EPS”)EPS from ongoing operations. Payouts vary according to goal achievement.operations achieved. No payout is earnedpayouts will occur if average growth in EPS growthfrom ongoing operations over the three-year period is less than 1.7% and no payouts will exceed 150% of target award.
Performance share awards are denominated in shares of SCANA's common stock. The number of performance shares into which awards are denominated at grant is calculated by multiplying the minimumNamed Executive Officer’s base salary by a target percentage, and dividing the product by the discounted opening stock price on the date of grant. The target percentage is derived from market survey data of the pre-established growth range goal. Executives earn threshold payouts (50%peer companies listed above under “Factors Considered in Setting Senior Executive Officer Compensation - - Use 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 performanceMarket Surveys and Peer Group Data.” The discounted stock price 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 andprovided to us by our compensation consultants. Performance share awards may be paid in stock or cash or a combination of stock and cash at SCANA’sour discretion. Based on past practices, we currently anticipate that payouts will be in cash. Payouts are based on the closing market price of SCANA's common stock on the last date of the plan cycle.
The allocation of 60% of awards to three-year TSR and 40% to EPS from ongoing operations was made to weight the external performance measure slightly higher than the internal performance measure.
2006 Payouts Under Performance Share Awards and Performance Unit Awards Granted in 2004
Performance Share Awards
Payouts for target performance share awards granted in 2004 for the 2004-2006 performance period were based on achieving TSR in the top two-thirds of the TSR for the Long-Term Equity Compensation Plan peer group over the three-year period. Executives would earn threshold payouts (equal to 50% of target award) if SCANA ranked at the 33rd percentile in relation to the peer group's three-year TSR performance. Target payouts (equal to 100% of target award) would be earned if SCANA ranked at the 50th percentile in relation to the peer group's three-year TSR performance. Maximum payouts (equal to 150% of target award) would be earned if SCANA ranked at or above the 75th percentile in relation to the peer group's three-year TSR performance. Payouts were scaled between 50% and 150% based on the actual percentile achieved. No payouts would be earned if TSR were at less than the 33rd percentile and no payouts would exceed 150% of the target award.
For the three-year performance period 2004-2006, TSR was below the 33rd percentile of the peer group's TSR which resulted in no payouts for the period.
Performance Unit Awards
Payouts for performance unit awards granted in 2004 for the 2004-2006 performance period were based on meeting projections for three-year average growth in EPS from ongoing operations. Senior executive officers would earn threshold payouts (equal to 50% of target award) at 2% average growth, target payouts (equal to 100% of target award) at 4% average growth and maximum payouts (equal to 150% of target award) at or above 6% average growth. Payouts were scaled between 50% and 150% based on the actual growth in EPS from ongoing operations achieved. No payouts would occur if average growth in EPS from ongoing operations over the period was less than 2% and no payouts would exceed 150% of target award. These threshold, target and maximum payout levels were consistent with the earnings growth guidance provided publicly by management at the time of the grants.
For the three-year performance period 2004-2006, average growth in EPS from ongoing operations fell below the 2% threshold which resulted in no payouts for the period.
Retirement and Other Benefit Plans
SCANA currently sponsors the following retirement benefit plans which are available to eligible senior officers of SCE&G (as such, these plans may be referred to herein as "our" plans):
| · | a tax qualified defined benefit retirement plan (the “Retirement Plan”), |
| · | a non-tax qualified defined benefit Supplemental Executive Retirement Plan (the “SERP”) for our senior executive officers, |
| · | a tax qualified defined contribution plan (the “401(k) Plan”), and |
| · | a non-tax qualified defined contribution Executive Deferred Compensation Plan (the “EDCP”) for our senior executive officers. |
All employees who have met eligibility requirements may participate in the Retirement Plan and the 401(k) Plan.
The SERP and the EDCP plans are designed to provide a benefit to senior executive officers who participate in the Retirement Plan or 401(k) Plan (our tax-qualified retirement plans) and whose participation in those tax-qualified plans is otherwise limited by government regulation. The SERP and EDCP participants are provided with the benefits to which they would have been entitled under the Retirement Plan or 401(k) Plan had their participation not been limited. At present, certain executive officers including the Named Executive Officers are participants in the SERP and/or EDCP. The SERP and the EDCP are described under the caption “Potential Payments Upon Termination or Change in Control - Retirement Benefits.” We provide the SERP and EDCP benefits because they allow our senior executive officers the opportunity to defer the same percentage of their compensation as other employees. We also believe, based on market survey data, that these plans are necessary to make our senior executive officer retirement benefits competitive.
We also provide other benefits such as medical, dental, life and disability insurance, which are available to all of our employees. In addition, we provide certain of our executive officers with additional long-term disability insurance and term life insurance.
Termination, Severance and Change in Control Arrangements
We have entered into arrangements with certain of our senior executive officers, including our Named Executive Officers, that provide for payments to them in the event of a change in control of SCANA or SCE&G. These arrangements, including the triggering events for payments and possible payment amounts, are described under the caption “Potential Payments Upon Termination or Change in Control.” These arrangements are not uncommon for executives at the level of our Named Executive Officers including executives of the companies included in our compensation market survey information, and are generally expected by those holding such positions. We believe these arrangements are an important factor in attracting and retaining our senior executive officers by assuring them financial and employment status protections in the event control of SCANA or SCE&G changes. We believe such assurances of financial and employment protections help free executives from personal concerns over their futures, and, thereby, can help to align their interests more closely with those of shareholders in negotiating transactions that could result in a change in control.
Perquisites
We provide a number of perquisites to senior executive officers as summarized below.
Company Aircraft
SCANA maintains two turboprop aircraft for the use of officers and managers in their travels to various operations throughout our service areas, as well as to meet with regulatory bodies, industry groups and financial groups, principally in Washington, D. C. and New York, New York. Our senior executive officers may use the aircraft for business purposes on a non-exclusive basis. The aircraft may also be used from time to time to transport directors to and from meetings and committee meetings of the Board of Directors. Spouses or close family members of directors and senior executive officers occasionally accompany a director or senior executive officer on the aircraft when the director or executive officer is flying for our business purposes. On very rare occasions, a senior executive officer may use our aircraft for personal use that is not in connection with a business purpose. We impute income to the executive for certain expenses related to such use.
For purposes of determining total 2006 compensation, we valued the aggregate incremental cost of the personal use of the aircraft using a method that takes into account the variable expenses associated with operating the aircraft, which variable expenses are only incurred if the planes are flying. Items included in our aggregate incremental cost are as follows: aircraft fuel and oil expenses per hour of flight; crew salaries; maintenance, parts and external labor (inspections and repairs) per hour of flight; aircraft accrual expenses per hour of flight; landing/parking/flight planning services expenses; crew travel expenses; and supplies and catering.
Medical Examinations
We provide each of our senior executive officers the opportunity to have a comprehensive annual medical examination from Duke University, the Medical University of South Carolina or the physician of his or her choice. We believe this examination helps encourage health-conscious senior executive officers, and helps us plan for any health related retirements or resignations.
Security Systems
We offer free installation and provide monitoring of home security systems for our senior executive officers. Because we operate a nuclear facility and provide essential services to the public, we believe we have a duty to help assure uninterrupted and safe operations by protecting the safety and security of our senior executive officers. We provide such installation and monitoring at multiple homes for some senior executive officers.
Other Perquisites
We provide a taxable allowance to our senior executive officers for financial counseling services, including tax preparation and estate planning services. We value this benefit based on the actual charges. We also pay the initiation fees and monthly dues for one dining club membership for each senior executive officer for business use. We allow spouses to accompany directors and senior executive officers to our quarterly Board meetings because we believe social gatherings of directors and senior executive officers in connection with these meetings increases collegiality. Some of our meetings are at resort locations where resort amenities may be provided.
Accounting and Tax Treatments of Compensation
Deductibility of Executive Compensation
Section 162(m) of the Internal Revenue Code establishes a limit on the deductibility of annual compensation in excess of $1,000,000 for certain senior executive officers, including the Named Executive Officers. Certain performance-based compensation approved by shareholders is not subject to the deduction limit. The Long-Term Equity Compensation Plan is qualified so that most performance-based awards under that plan constitute compensation that is not subject to Section 162(m). The Short-Term Incentive Plan does not meet 162(m) deductibility requirements. To maintain flexibility in compensating senior executive officers in a manner designed to promote various corporate goals, the Human Resources Committee has not adopted a policy that all compensation must be deductible. Since Mr. Timmerman’s salary is above the $1,000,000 threshold, we may not deduct a portion of his compensation. The Human Resources Committee considered these tax and accounting effects in connection with its deliberations on senior executive compensation.
Nonqualified Deferred Compensation
On January 1, 2005, the Internal Revenue Code was amended to include a new Section 409A, which would impose interest and penalties on receipt of certain types of deferred compensation payments. Deferred compensation plans are required to be amended to comply with the requirements of Section 409A, if necessary, by the end of 2007 to avoid imposition of such interest and penalties. In the meantime, the plans must operate in good faith compliance with Section 409A, and we believe our deferred compensation plans meet this requirement. We have determined that amendments will be required to the Supplemental Executive Retirement Plan, the Executive Deferred Compensation Plan, the Key Executive Severance Benefits Plan and the Supplementary Key Executive Severance Benefits Plan to cause these plans to comply with Section 409A. The Human Resources Committee expects to address these amendments in 2007.
Accounting for Stock Based Compensation
Beginning January 1, 2006, we began accounting for stock based compensation in accordance with the requirements of FASB Statement 123(R).
Compensation for 2007
On February 15, 2007, the Board, on the recommendation of the Human Resources Committee, adopted criteria for performance awards for the 2007 - 2009 performance cycle under the Long-Term Equity Compensation Plan. These criteria are discussed under “- - Long-Term Equity Compensation Plan - - Performance Share Awards.”
On the same day, upon recommendation of the Human Resources Committee, the Board approved base salaries for our Named Executive Officers and criteria for performance awards under our Short-Term Annual Incentive Plan for the year 2007. Such base salaries and performance award criteria do not differ materially from year 2006 levels.
As noted above, in 2007, the Human Resources Committee expects to make amendments to our deferred compensation plans as necessary to address issues raised by Internal Revenue Code Section 409A.
Financial Restatement
Although we have never experienced such a situation, our Board of Directors’ policy is to consider on
a case-by-case basis a retroactive adjustment to any cash or equity-based incentive compensation paid to our senior executive officers where payment was conditioned on achievement of certain financial results that were subsequently restated or otherwise adjusted in a manner that would reduce the size of a prior award or payment.
Security Ownership Guidelines for Executive Officers
We do not currently have any equity or other security ownership guidelines or requirements for executive officers (specifying applicable amounts and forms of ownership), or any policies regarding hedging the economic risk of such ownership. However, all of our senior executive officers have a significant amount of their 401(k) plan accounts invested in SCANA stock.
Compensation Committee Interlocks and Insider Participation
During 2006, decisions on various elements of executive compensation were made by the Human Resources Committee. No officer, employee or former officer or any related person of SCANA or any of its subsidiaries served as a member of the Human Resources Committee.
The directors who served on the Human Resources Committee during 2006 were:
Mr. G. Smedes York, Chairman
Mr. Bill L. Amick*
Mr. James A. Bennett
Mr. William C. Burkhardt
Mrs. Sharon A. Decker
Mr. D. Maybank Hagood
Ms. Lynne M. Miller
Mr. Maceo K. Sloan
*Mr. Amick served on the Committee until August 2, 2006.
Compensation Committee Report
The Human Resources Committee has reviewed and discussed with management the “Compensation Discussion and Analysis” included herein. Based on that review and discussion, the Human Resources Committee recommended to our Board of Directors that the “Compensation Discussion and Analysis” be included in our Annual Report on Form 10-K for the year ended December 31, 2006 for filing with the Securities and Exchange Commission.
Mr. G. Smedes York (Chairman)
Mr. James A. Bennett
Mr. William C. Burkhardt
Mrs. Sharon A. Decker
Mr. D. Maybank Hagood
Ms. Lynne M. Miller
Mr. Maceo K. Sloan
SUMMARY COMPENSATION TABLE
The following table summarizes information about compensation paid or accrued during 2006 to our Chief Executive Officer, our Chief Financial Officer and former Chief Financial Officer and our three next most highly compensated executive officers. (As noted in the Compensation Discussion and Analysis, we refer to these persons as our Named Executive Officers.)
Name and Principal Position | Year | Salary ($) | Bonus ($)(1) | Stock Awards ($)(2) | Option Awards ($) | Non- Equity Incentive Plan Compen-sation ($)(3) | Change in Pension Value and Nonquali- fied Deferred Compensa-tion Earnings ($)(4) | All Other Compen-sation ($)(5) | Total ($) |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| W.B. Timmerman, Chief Executive Officer | 2006 | $1,002,700 | $170,459 | $-1,398,181 | 0 | $426,148 | $274,724 | $73,629 | $549,479 |
J. E. Addison, Chief Financial Officer(6) | 2006 | $278,990 | $27,916 | $-156,699 | 0 | $69,789 | $21,981 | $30,091 | $272,068 |
K. B. Marsh, President and Chief Operating Officer (7) | 2006 | $516,183 | $66,916 | $-478,476 | 0 | $167,290 | $59,934 | $63,816 | $395,663 |
| F. P. Mood, Jr., Senior Vice President and General Counsel | 2006 | $350,000 | $35,000 | $27,075(8) | 0 | $87,500 | $59,582 | $41,051 | $600,208 |
| J. C. Bouknight, Senior Vice President | 2006 | $290,000 | $29,000 | $-160,656 | 0 | $72,500 | $38,872 | $32,901 | $302,617 |
S. A. Byrne, Senior Vice President | 2006 | $400,400 | $48,048 | $-346,911 | 0 | $120,120 | $40,226 | $45,550 | $307,433 |
(1)Discretionary bonus awards as permitted under the Short-Term Annual Incentive Plan, which are discussed in further detail under “- - Compensation Discussion and Analysis - - Short-Term Annual Incentive Plan - - Discretionary Bonus Award.”
(2) The information in this column relates to performance share awards (liability awards) under the Long-Term Equity Compensation Plan. This plan is discussed under "- - Compensation Discussion and Analysis - Long-Term Equity Compensation Plan - 2006 Long-Term Incentive Plan Awards." The assumptions made in valuation of stock awards are set forth in Note 3 under Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCE&G in Part II above.
As explained below, the amounts in this column do not represent deductions from compensation actually paid to our Named Executive Officers, or repayments by them of previously awarded compensation. Rather, this column reflects the aggregate amounts recorded as (negative) compensation expense in the income statement and amounts which were (credited to) capitalized costs in the financial statements for the year ended December 31, 2006, for all three plan performance cycles which were in operation during the year. As such, the amounts reported include not only compensation cost recognized with respect to awards granted in 2006 for the 2006-2008 plan cycle, but also reductions of accruals in prior years of compensation cost related to awards granted in 2004 for the 2004-2006 plan cycle and in 2005 for the 2005-2007 plan cycle.
During 2006, SCANA's EPS from ongoing operations did not grow, and its TSR performance lagged the peer group. As such, awards for the 2004-2006 plan cycle, for which significant amounts had been accrued in prior years, fell below performance threshold payout levels, with requisite reductions of prior accruals being recorded in 2006. Similarly, prior accruals related to the 2005-2007 plan cycle were reduced in 2006 based on this decline in relative TSR and lower earnings growth performance. These reductions of prior compensation cost accruals were only partially offset by accruals related to the 2006-2008 plan cycle, which accruals were also limited by the 2006 TSR and EPS from ongoing operations performance.
(3) Payouts under the Short-Term Annual Incentive Plan, which is discussed in further detail under "- - Compensation Discussion and Analysis - Short-Term Annual Incentive Plan."
(4) The aggregate change in the actuarial present value of each Named Executive Officer's accumulated benefits under SCANA's Retirement Plan and Supplemental Executive Retirement Plan from December 31, 2005 to December 31, 2006, determined using interest rate and mortality rate assumptions consistent with those used in our financial statements. These plans are discussed under "- - Compensation Discussion and Analysis - Retirement and Other Benefit Plans."
(5) All other compensation paid to each Named Executive Officer, including company contributions to the 401(k) Plan and the Executive Deferred Compensation Plan, tax reimbursements with respect to perquisites or other personal benefits, and life insurance premiums on policies owned by Named Executive Officers. For 2006, contributions to defined contribution plans were as follows: Mr. Timmerman - $66,420; Mr. Addison - $26,306; Mr. Marsh - $60,044; Mr. Mood - $36,750; Mr. Bouknight - $29,145; Mr. Byrne - $42,042. For 2006, tax reimbursements with respect to perquisites or other personal benefits were as follows: Mr. Timmerman - $1,463; Mr. Addison - $716; Mr. Marsh - $133; Mr. Mood - $205; Mr. Bouknight - $527; and Mr. Byrne - $442. Neither life insurance premiums on policies owned by the Named Executive Officers nor perquisites exceeded $10,000 for any Named Executive Officer.
(6) Mr. Addison was appointed as our Chief Financial Officer in April, 2006.
(7) Mr. Marsh served as our Chief Financial Officer until April, 2006, at which time he was appointed as the President and Chief Operating Officer of SCE&G.
(8) Mr. Mood did not participate in the 2004-2006 or 2005-2007 cycles of the Long-Term Equity Compensation Plan and, therefore, no accruals under these cycles had to be reversed with respect to him. The amount shown for Mr. Mood represents the accruals related to the award under the 2006-2008 cycle as discussed under footnote 2 above.
2006 GRANTS OF PLAN-BASED AWARDS
The following table sets forth each grant of an award made to a Named Executive Officer under our compensation plans during 2006.
| Name | Grant Date | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1) | Estimated Future Payouts Under Equity Incentive Plan Awards(2) | All Other Stock Awards:Number of Shares of Stock or Units (#) | All Other Option Awards: Number of Securi-ties Under-lying Options (#) | Exer-cise or Base Price of Option Awards ($/Sh) | Grant Date Fair Value of Stock and Option A-wards |
Thresh-old ($) | Target ($) | Maximum ($) | Thresh-old (#) | Target (#) | Maxi-mum (#) | | | | |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) |
| W. B. Timmerman | 2-16-06 | $426,148 | $852,295 | $1,278,443 | 35,044 | 70,088 | 105,132 | | | | |
| J. E. Addison | 2-16-06 | $69,789 | $139,578 | $209,367 | 4,356 | 8,711 | 13,067 | | | | |
K. B. Marsh | 2-16-06 | $167,290 | $334,580 | $501,870 | 12,397 | 24,794 | 37,191 | | | | |
F. P. Mood, Jr. | 2-16-06 | $87,500 | $175,000 | $262,500 | 5,811 | 11,621 | 17,432 | | | | |
| J. C. Bouknight | 2-16-06 | $72,500 | $145,000 | $217,500 | 4,308 | 8,615 | 12,923 | | | | |
S. A. Byrne | 2-16-06 | $120,120 | $240,240 | $360,360 | 7,697 | 15,393 | 23,090 | | | | |
(1) The amounts in columns (c), (d) and (e) represent the threshold, target and maximum awards that could have been paid under the Short-Term Annual Incentive Plan if performance criteria were met. Performance criteria were met only at the threshold level, and therefore, as reflected in the Summary Compensation Table, the amounts paid were those shown in column (c). A discussion of the Short-Term Annual Incentive Plan is included under “- - Compensation Discussion and Analysis - Short-Term Annual Incentive Plan.” See also, “- - Compensation Discussion and Analysis - - Short-Term Annual Incentive Plan - - Discretionary Bonus Award” for a discussion of the discretionary bonus paid under this plan.
(2) Represents potential future payouts of the 2006-2008 cycle of performance share awards under the Long-Term Equity Compensation Plan. Payout of performance share awards will be dictated by SCANA's performance against pre-determined measures of TSR and growth in EPS from ongoing operations over the three-year plan cycle. A discussion of the components of the performance share awards is included under "- - Compensation Discussion and Analysis - - Long-Term Equity Compensation Plan - - Performance Share Awards."
OUTSTANDING EQUITY AWARDS AT 2006 FISCAL YEAR-END
The following table sets forth certain information regarding unexercised options and equity incentive plan awards for each Named Executive Officer outstanding as of December 31, 2006.
| | Option Awards | Stock Awards |
| Name | Number of Securities Underlying Unexercised Options (#) Exer-cisable(1) | Number of Securities Underlying Unexercised Options (#) Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | Option Exercise Price ($) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(2)(4) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(3) (4) |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| W. B. Timmerman | 123,067 | | | $27.52 | 02/21/2012 | | | 99,153 | $4,027,595 |
J. E. Addison | | | | | | | | 10,157 | $412,577 |
K. B. Marsh | | | | | | | | 32,968 | $1,339,160 |
F. P. Mood, Jr. | | | | | | | | 14,692 | $596,789 |
| J. C. Bouknight | | | | | | | | 11,102 | $450,963 |
S. A. Byrne | 21,492 | | | $27.52 | 02/21/2012 | | | 19,276 | $782,991 |
(1) The vesting date of Mr. Byrne’s options was February 21, 2005. All other options were exercised after December 31, 2006.
(2) Assuming the performance criteria are met, the vesting dates of these awards would be as follows: Mr. Timmerman - 50,091 shares would vest on December 31, 2007 and 49,062 shares would vest on December 31, 2008; Mr. Addison - 4,059 shares would vest on December 31, 2007 and 6,098 shares would vest on December 31, 2008; Mr. Marsh - 15,612 shares would vest on December 31, 2007 and 17,356 shares would vest on December 31, 2008; Mr. Mood - 6,557 shares would vest on December 31, 2007 and 8,135 shares would vest on December 31, 2008; Mr. Bouknight - 5,071 shares would vest on December 31, 2007 and 6,031 shares would vest on December 31, 2008; Mr. Byrne - 8,501 shares would vest on December 31, 2007 and 10,775 shares would vest on December 31, 2008.
(3) The market value of these awards is based on the closing market price of SCANA common stock on the New York Stock Exchange on December 29, 2006 of $40.62.
(4) For the 2004-2006 plan cycle, no shares vested or were earned because performance criteria were not met. For the 2005-2007 cycle, performance shares tracking against SCANA's total shareholder return (60% of target shares) are projected to result in zero payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the threshold performance measure for the TSR portion of the shares. Performance shares tracking against SCANA's growth in EPS from ongoing operations (40% of target shares) for the 2005-2007 cycle are projected to result in a payout between threshold and target. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the target performance measure for the growth in EPS from ongoing operations portion of the shares. For the 2006-2008 cycle, performance shares tracking against SCANA's total shareholder return (60% of target shares) are projected to result in zero payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the threshold performance measure for the TSR portion of the shares. Performance shares tracking against SCANA's growth in EPS from ongoing operations (40% of target shares) for the 2006-2008 cycle are projected to result in a payout between threshold and target. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the target performance measure for the growth in EPS from ongoing operations portion of the shares.
2006 OPTION EXERCISES AND STOCK VESTED
The following table sets forth information about exercises of stock options for each Named Executive Officer during 2006. No stock awards vested in 2006.
| | | Option Awards | | Stock Awards | |
| Name | | Number of Shares Acquired on Exercise (#) | | Value Realized on Exercise ($) | | Number of Shares Acquired on Vesting (#) | | Value Realized on Vesting ($) | |
| (a) | | (b) | | (c) | | (d) | | (e) | |
W. B. Timmerman | | | | | | | | | | | | | |
J. E. Addison | | | | | | | | | | | | | |
K. B. Marsh | | | 25,939 | | $ | 297,779 | | | | | | | |
F. P. Mood, Jr. | | | | | | | | | | | | | |
J. C. Bouknight | | | | | | | | | | | | | |
S. A. Byrne | | | 27,938 | | $ | 317,369 | | | | | | | |
PENSION BENEFITS
The following table sets forth certain information relating to the Retirement Plan and Supplemental Executive Retirement Plan (SERP).
| Name | | Plan Name | | Number of Years Credited Service (#)(1) | | Present Value of Accumulated Benefit ($)(1) (2) | | Payments During Last Fiscal Year ($) | |
| (a) | | (b) | | (c) | | (d) | | (e) | |
W. B. Timmerman | | | SCANA Ret. Plan SCANA SERP | | | 28 28 | | $ $ | 792,631 2,090,423 | | | 0 0 | |
J. E. Addison | | | SCANA Ret. Plan SCANA SERP | | | 15 15 | | $ $ | 128,406 68,597 | | | 0 0 | |
K. B. Marsh | | | SCANA Ret. Plan SCANA SERP | | | 22 22 | | $ $ | 423,655 369,986 | | | 0 0 | |
F. P. Mood, Jr. | | | SCANA Ret. Plan SCANA SERP | | | 2 2 | | $ $ | 35,333 54,862 | | | 0 0 | |
J. C. Bouknight | | | SCANA Ret. Plan SCANA SERP | | | 2 2 | | $ $ | 31,379 42,836 | | | 0 0 | |
S. A. Byrne | | | SCANA Ret. Plan SCANA SERP | | | 11 11 | | $ $ | 110,324 174,521 | | | 0 0 | |
(1) Computed as of December 31, 2006, the plan measurement date used for financial statement reporting purposes.
(2) Present value calculation determined using current account balances for each Named Executive Officer as of the end of 2006, based on assumed retirement at normal retirement age (specified as age 65) and other assumptions as to valuation method, interest rate and other material factors as set forth in Note 3 under Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCE&G in Part II above.
The SCANA Retirement Plan and Supplemental Executive Retirement Plan are both cash balance defined benefit plans. The plans provide for full vesting after five years of service or after reaching age 65. All named executive officers are fully vested in both plans with the exception of Mr. Bouknight.
Defined Benefit PlansRetirement Plan
SCANA sponsors a tax qualified defined benefit retirement plan (the "Retirement Plan") in which employeesall of its subsidiaries, including SCE&G, participate. The plan utilizesuses 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 TableNamed Executive Officers participate under the cash balance formula of the plan.Retirement Plan.
The cash balance formula is expressed in the form of a hypothetical account balance. Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances is determined annually and is equal to the average rate for 30-year Treasury Notes for December of the previous calendar year. Compensation credits equal 5% of compensation underup to the Social Security wage base and 10% of compensation in excess of the Social Security wage base.
Supplemental Executive Retirement Plan
In addition to itsthe Retirement Plan for all employees, SCANA provides a Supplemental Executive Retirement Plans ("SERPs")Plan for certain eligible employees, including officers. A SERPthe Named Executive Officers. The Supplemental Executive Retirement Plan is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations. The Supplemental Executive Retirement Plan is discussed under the caption “- - Potential Payments Upon Termination or Change in Control - Retirement Benefits,” and under the caption “- - Compensation Discussion and Analysis - - Retirement and Other Benefit Plans.”
2006 NONQUALIFIED DEFERRED COMPENSATION
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),following table sets forth information with respect to the executive officers namedExecutive Deferred Compensation Plan:
| Name | | Executive Contributions in Last FY ($)(1) | | Registrant Contributions in Last FY ($)(1) | | Aggregate Earnings in Last FY ($) | | Aggregate Withdrawals/ Distributions ($) | | Aggregate Balance at Last FYE ($) | |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | |
W. B. Timmerman | | $ | 53,220 | | $ | 53,220 | | $ | 155,692 | | | 0 | | $ | 2,652,609 | |
J. E. Addison | | $ | 13,572 | | $ | 13,387 | | $ | 19,862 | | | 0 | | $ | 325,102 | |
K. B. Marsh | | $ | 46,962 | | $ | 46,844 | | $ | 143,723 | | | 0 | | $ | 1,105,338 | |
F. P. Mood, Jr. | | $ | 23,550 | | $ | 23,550 | | $ | 7,434 | | | 0 | | $ | 68,533 | |
J. C. Bouknight | | $ | 15,945 | | $ | 15,945 | | $ | 7,471 | | | 0 | | $ | 62,580 | |
S. A. Byrne | | $ | 52,877 | | $ | 28,842 | | $ | 24,551 | | | 0 | | $ | 439,168 | |
(1) The amounts reported in Columns (b) and (c) are reflected 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.Table.
Termination, Severance and Change in Control ArrangementsExecutive Deferred Compensation Plan
SCANA maintains an Executive Benefit Plan Trust. The purpose ofWe have adopted 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, in which our Named Executive Officers may participate if they choose to do so. The plan is a non-qualified deferred compensation plan. Each participant may elect to defer up to 25% of that part of his or her eligible earnings (as defined in the 401(k) plan) that exceeds the limitation on compensation otherwise required under Internal Revenue Code Section 401(a)(17), and without regard to any deferrals or the foregoing of compensation. For 2006, participants could defer on eligible earnings in excess of $220,000. In addition, a participant may elect to defer up to 100% of any performance share award for the year under our Long-Term Equity Compensation Plan. We match the amount of compensation deferred by each participant up to 6% of the participant’s eligible earnings in excess of the limit amount not including any performance share award.
(2)We record the amount of each participant’s deferred compensation and the amount we match in a special ledger. We also credit a rate of return to each participant’s special ledger account based on hypothetical investment alternatives chosen by the participant. The committee that administers the Executive Deferred Compensation Plan designates various hypothetical investment alternatives from which the participants may choose. Using the results of the hypothetical investment alternatives chosen, we credit each participant’s special ledger account with the amount it would have earned if the account amount had been invested in that alternative. If the chosen hypothetical investment alternative loses money, the participant’s special ledger account is reduced by the corresponding amount. All amounts credited to a participant’s special ledger accounts continue to be credited or reduced pursuant to the chosen investment alternatives until such amounts are paid in full to the participant or his beneficiary. No actual investments are made. The investment alternatives are only used to generate a rate of increase (or decrease) in the special ledger accounts and amounts paid to participants are solely our obligation. In connection with this plan, the Board has established a grantor trust (known as the “SCANA Corporation Executive Benefit Plan Trust”) for the purpose of accumulating funds to satisfy the obligations we incur under the Plan. At any time prior to a change in control we may transfer assets to the trust to satisfy all or part of our obligations under the Plan. Notwithstanding the establishment of the Trust, the right of participants to receive future payments is an unsecured claim against us.The trust has been partially funded with respect to ongoing deferrals and Company matching funds since October 2001.
In 2006, the Named Executive Officers’ special ledger accounts were credited with earnings (or losses) based on the following investment alternatives and rates of returns:
INVESCO Stable Value Trust (4.30%); PIMCO Total Return (3.74%); Dodge & Cox Common Stock (18.53%); American Century Inc. & Growth Adv. (16.86%); INVESCO 500 Index Trust (15.37%); Pioneer Oak Ridge Large Cap Growth (2.61%); T. Rowe Price Mid Cap Value (20.24%); Lord Abbett Growth Opportunity (7.66%); RS Partners (11.22%); Vanguard Explorer (9.88%); American Funds Europacific Growth (21.87%); SCANA Corporation Supplemental ExecutiveStock (7.60%); Janus Small Cap Value (12.4%); Vanguard Target Retirement PlanIncome (6.38%); Vanguard Target Retirement 2005 (8.23%); Vanguard Target Retirement 2015 (11.42%); Vanguard Target Retirement 2025 (13.24%); Vanguard Target Retirement 2035 (15.24%); Vanguard Target Retirement 2045 (15.98$). The measures for calculating interest or other plan earnings are based on the investments chosen by the manager of each investment vehicle, except the SCANA Stock Fund, the earnings of which are based on the value of SCANA's common stock.
(3)The hypothetical investment alternatives may be changed at any time on a prospective basis by the participants in accordance with the telephone, electronic, and written procedures and forms adopted by the committee for use by all participants on a consistent basis.SCANA Corporation Long-Term Equity
All amounts deferred under the Executive Deferred Compensation Plan, matching contributions and earnings credited to a participant’s special ledger account are paid, or begin to be paid, to the participant either in a lump sum or installments for up to 15 years at a later time chosen by the participant; provided, however, that the deferred amounts are to be paid, or to begin to be paid, as soon as practicable following the participant’s death, disability, retirement or other termination of employment.
A participant may request and receive, with the approval of the committee, an acceleration of the payment of some or all of the participant’s special ledger account due to severe financial hardship as the result of extraordinary and unforeseeable circumstances arising as a result of events beyond the individual’s control. With respect to amounts earned and vested before January 1, 2005, a participant may also obtain payment of his special ledger account on an accelerated basis by forfeiting 10% of the amount accelerated or by making the election to accelerate the payment not less than 12 months before the payment will be made. Additionally, the plan provides for the acceleration of payments following a change in control of the Company. The change in control provisions are discussed under “- - Potential Payments Upon Termination or Change in Control - - Change in Control Arrangements.”
We plan to amend all available distribution and withdrawal options with respect to amounts earned or vested after 2004 to conform to the requirements for deferred compensation under Section 409A of the Internal Revenue Code. The Internal Revenue Service has issued proposed and preliminary guidance under Section 409A. The extent of any changes needed to conform to Section 409A will not be clear until after final guidance is issued. Currently, the Internal Revenue Service requires that changes to conform to Section 409A generally be made by December 31, 2007. However, we were required to operate in good faith compliance from January 1, 2005 forward, subject to guidance issued by the Internal Revenue Service.
Potential Payments Upon Termination or Change in Control
(4)SCANA Corporation Short-Term Annual Incentive PlanChange in Control Arrangements
(5) Triggering Events for Payments under the Key Executive Severance Benefits Plan and the Supplementary Key Executive Severance Benefits Plan
We have adopted the SCANA Corporation Key Executive Severance Benefits Plan
(6) and the SCANA Corporation Supplementary Key Executive Severance Benefits Plan,
which provide for payments to our senior executive officers in connection with a change in control of the Company. The Key Executive Severance Benefits Plan and each of the plans listed at (1) through (4) provide(the “Severance Plan”) provides for payment of benefits in a lump sum to the eligible participants immediately upon a Changechange in Control,control unless the Key Executive Severance Benefits Plan isplan has been terminated prior to the Changechange in Control.control. This plan is designed to provide for benefits in the event of a change in control that our Board deems to be hostile. In contrast,the event of a change in control that our Board deems to be friendly, we anticipate that the Board would terminate the Severance Plan prior to the change in control. If the Severance Plan is terminated, the Supplementary Key Executive Severance Benefits Plan is operative(the “Supplementary Severance Plan”) would provide for a periodpayment of benefits if, within 24 months followingafter the change in control, we terminate 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 fromsenior executive officer’s employment without "Just Cause,"just cause or (ii)if the participant voluntarilysenior executive officer terminates his or her employment for "Good Reason" (as these terms are definedgood reason.
Both plans provide that a “change in control” will be deemed to occur under the following circumstances:
| · | if any person or entity becomes the beneficial owner, directly or indirectly, of 25% or more of the combined voting power of the outstanding shares of SCANA common stock; |
| · | if, during a consecutive two-year period, a majority of our directors cease to be individuals who either (a) were |
directors on the Board at the beginning of such period, or (b) became directors after the beginning of such period but whose election by the Board, or nomination for election by our shareholders, was approved by at least two-thirds of the directors then still in office who either were directors at the beginning of such period, or whose election or nomination for election was previously so approved;
| · | if SCANA shareholders approve (a) a merger or consolidation of SCANA with another corporation (except a merger or consolidation in which SCANA outstanding voting shares prior to such transaction continue to represent at least 80% of the combined voting power of the surviving entity's outstanding voting shares after such transaction), (b) a plan of complete liquidation of SCANA, or (c) an agreement to sell or dispose of all or substantially all of SCANA’s assets; or |
| · | if SCANA’s shareholders approve a plan of complete liquidation, or sale or disposition of, South Carolina Electric & Gas Company, Carolina Gas Transmission Corporation, or any of SCANA’s other subsidiaries that the Board designates to be a material subsidiary. (This last provision would constitute a change in control only with respect to participants exclusively assigned to the affected subsidiary.) |
As noted above, benefits under the Supplementary Key Executive Severance Benefits Plan).
Benefit distributions relativePlan would be triggered if we terminated the Severance Plan prior to a Changechange in Control, ascontrol, and, within 24 months after the change in control, we terminated the senior executive officer’s employment without just cause or if the senior executive officer terminated his or her employment for good reason. Under the plan, we would be deemed to which eitherhave “just cause” for terminating the Key Executive Severance Benefits Planemployment of a senior executive officer if he or the Supplementary Key Executive Severance Benefits Plan is operative, include an amount equalshe:
| · | willfully and continually failed to perform his or her duties after we made demand for substantial performance; |
| · | willfully engaged in conduct that is materially injurious to us; or |
| · | were convicted of a felony or certain misdemeanors. |
A senior executive officer would be deemed to estimated federal, state and local income taxes and any estimated applicable excise taxes owed by plan participants on those benefits.have “good reason” for terminating his or her employment if:
| · | he or she were assigned to duties inconsistent with his or her duties, or had a reduction or alteration in the nature or status of his or her responsibilities, from those in effect 90 days prior to the change in control; |
| · | we reduced his or her base salary as in effect 30 days prior to the occurrence of certain preliminary actions preceding the change in control (such as the execution of agreements relating to a change in control, public announcements by us of our intentions, transfers of securities representing at least 8½% of SCANA's common stock or the adoption of board resolutions with respect thereto); |
| · | after the change in control, we required him or her to be based more than 25 miles from his or her location as of the effective date of the Supplementary Severance Plan; |
| · | we failed to continue to offer any annual or long-term incentive programs for officers which were in effect on the effective date of the change in control, or other employee benefit plans, policies, practices or arrangements in which he or she participates, unless similar plans of equal value are put in place, or we failed to permit him or her to continue participation on substantially the same basis as existed on the date of the change in control; |
| · | we failed to obtain a satisfactory agreement from any successor to assume and perform the Supplementary Severance Plan; or |
| · | we purported to terminate him or her without using a notice of termination that satisfies the requirements of the Supplementary Severance Plan. |
Potential Benefits Payable
The benefit distributionsbenefits we would be required to pay our senior executive officers under the Key Executive Severance Benefits Plan would include the following three benefits:immediately upon a change in control are as follows:
| · | An amount intended to approximate three times the sum of: (i) his or her annual base salary (before reduction for certain pre-tax deferrals) and (ii) his or her full targeted annual incentive award, in each case as in effect for the year in which the change in control occurs; |
| · | An amount equal to three times the sum of: (i) the participant's annual base salary in effectpresent value as of the date of the Changechange in Control and (ii)control of his or her accrued benefit, if any, under our Supplemental Executive Retirement Plan, determined prior to any offset for amounts payable under the officer's target annual incentive award in effect asSCANA Retirement Plan, increased by the present value of the date of the Change in Controladditional projected pay credits and periodic interest credits that would otherwise accrue under the Short-Term Annual Incentive Plan.plan (based on the plan's actuarial assumptions) assuming that he or she remained employed until reaching age 65, and reduced by his or her cash balance account under the SCANA Retirement Plan; and |
| · | An amount equal to the projected cost for medical, long-term disability and certain life insurance coverage for three years following the Changechange in Controlcontrol as though the participanthe or she had continued to be a SCANAour 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. |
AdditionalIn addition to the benefits payableabove, immediately upon a Changechange in Controlcontrol prior to which we had not terminated the Severance Plan (unless their agreements with us provide otherwise), our senior executive officers would also be entitled to benefits under our other plans in which the Key Executive Severance Benefits Plan is operable arethey participate as follows:
| · | A benefit distribution of all amounts credited to the participant'shis or her Executive Deferred Compensation Plan ledger account as of the date of the Changechange in Control.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 Changechange in Control,control, if any.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 Changechange in Control.control; |
| · | Under the Long-Term Equity Compensation Plan and related agreements, all nonqualified stock options awarded and non-vested target performance shares would become immediately exercisable or vested and remain exercisable throughout their original term or, in the case of performance shares, vested and payable within 30 days of the change in control; and |
| · | Any amounts previously earned, but not yet paid, under the terms of any of our other plans or programs. |
The benefits and their respective amounts underUnder the Supplementary Key Executive Severance Benefits Plan, senior executive officers would also be entitled to all of the benefits described above. In addition, interest would be the same as those described above, except thatpaid on the benefits payable with respect tounder the Executive Deferred Compensation Plan would be increased byat a rate equal to the sum of the prime interest rate as published in the Wall Street Journal on the most nearly precedingrecent publication date prior to the date of the Changechange in Controlcontrol plus 3%, calculated untilthrough the end of the month preceding the month in which the benefits are distributed. Any amounts payable under the Supplementary Severance Plan would be reduced by all amounts, if any, received under the Severance Plan.
In addition, benefit distributions to senior executive officers under either the Severance Plan or the Supplementary Severance Plan would also include payment of an amount (a "gross-up payment") reimbursing him or her for the amount of anticipated excise tax imposed under Section 4999 of the Internal Revenue Code (or any similar tax) on such benefits and the gross-up payment, and any income and employment tax and excise tax due with respect to the gross-up payment.
Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 29, 2006
Severance Plan
If we had been subject to a change in control as of December 29, 2006, and the Severance Plan had not been terminated, our Named Executive Officers would have been immediately entitled to the benefits outlined below.
Mr. Timmerman would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award - $5,565,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above - $812,000; an amount equal to insurance continuation benefits for three years - $34,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan - $5,754,000;and anticipated excise tax and gross-up payment - $5,290,000. The total value of these change in control benefits would have been $17,455,000. In addition, Mr. Timmerman would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award - $596,607; Executive Deferred Compensation Plan account balance - $2,652,609; Supplemental Executive Retirement Plan and Retirement Plan account balances- $3,056,000; vacation accrual - $69,000; as well as his 401(k) Plan account balance.
Mr. Addison would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award - $1,274,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above - $545,000; an amount equal to insurance continuation benefits for three years - $61,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan - $589,000; and anticipated excise tax and gross-up payment - $1,087,000. The total value of these change in control benefits would have been $3,556,000. In addition, Mr. Addison would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award - $97,705; Executive Deferred Compensation Plan account balance - $325,102; Supplemental Executive Retirement Plan and Retirement Plan account balances- $246,000; vacation accrual - $9,000; as well as his 401(k) Plan account balance.
Mr. Marsh would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award - $2,579,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above - $905,000; an amount equal to insurance continuation benefits for three years - $46,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan - $1,913,000; and anticipated excise tax and gross-up payment - $2,296,000. The total value of these change in control benefits would have been $7,739,000. In addition, Mr. Marsh would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award - $234,206; Executive Deferred Compensation Plan account balance - $1,105,338; Supplemental Executive Retirement Plan and Retirement Plan account balances - $934,000; vacation accrual - $9,000; as well as his 401(k) Plan account balance.
Mr. Mood would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award - $1,575,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above - $0; an amount equal to insurance continuation benefits for three years - $35,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan - $853,000;and anticipated excise tax and gross-up payment - $1,090,000. The total value of these change in control benefits would have been $3,553,000. In addition, Mr. Mood would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award - $122,500; Executive Deferred Compensation Plan account balance - $68,533; Supplemental Executive Retirement Plan and Retirement Plan account balances - $90,000; vacation accrual - $0; as well as his 401(k) Plan account balance.
Mr. Bouknight would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award - $1,305,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above - $445,000; an amount equal to insurance continuation benefits for three years - $44,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan - $644,000; and anticipated excise tax and gross-up payment - $1,043,000. The total value of these change in control benefits would have been $3,481,000. In addition, Mr. Bouknight would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award - $101,500; Executive Deferred Compensation Plan account balance - $62,580; Supplemental Executive Retirement Plan and Retirement Plan account balances - $0; vacation accrual - $7,000; as well as his 401(k) Plan account balance.
Mr. Byrne would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award - $1,922,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above - $807,000; an amount equal to insurance continuation benefits for three years - $63,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan - $1,119,000; and anticipated excise tax and gross-up payment - $1,716,000. The total value of these change in control benefits would have been $5,627,000. In addition, Mr. Byrne would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award - $168,168; Executive Deferred Compensation Plan account balance - $439,168; Supplemental Executive Retirement Plan and Retirement Plan account balances - $353,000; vacation accrual - $17,000; as well as his 401(k) Plan account balance.
In addition to the foregoing benefits, all option and stock awards set forth in the “2006 Outstanding Equity Awards at Fiscal Year-End” table would have vested for each Named Executive Officer.
Supplementary Severance Plan
If (i) we had been subject to a change in control in the past 24 months, (ii) the Severance Plan had been terminated prior to the change in control, and (iii) as of December 29, 2006, either we had terminated the employment of any of our Named Executive Officers without just cause or they had terminated their employment for good reason, such terminated Named Executive Officer would have been immediately entitled to all of the benefits outlined above, together with an amount equal to an increase in the amount payable with respect to his Executive Deferred Compensation Plan account, calculated as outlined above. The actual amount of any such additional payment would depend upon the date on which employment of the Named Executive Officer terminated subsequent to the change in control.
Compensation Committee InterlocksRetirement Benefits
Supplemental Executive Retirement Plan
The SCANA Corporation Supplemental Executive Retirement Plan (the “SERP”) is an unfunded nonqualified deferred compensation plan. The SERP was established for the purpose of providing supplemental retirement income to certain of our employees, including the Named Executive Officers, whose benefits under the Retirement Plan are limited in accordance with the limitations imposed by the Internal Revenue Code on the amount of annual retirement benefits payable to employees from qualified pension plans or on the amount of annual compensation that may be taken into account for all qualified plan purposes, or by certain other design limitations on determining compensation under the Retirement Plan.
Subject to the terms of the SERP, a participant becomes eligible to receive benefits under the SERP upon termination of his or her employment with us (or at such later date as may be provided in a participant’s agreement with us), if the participant has become vested in his or her accrued benefit under the Retirement Plan prior to termination of employment. However, if a participant is involuntarily terminated following or incident to a change in control and Insider Participationprior to becoming fully vested in his or her accrued benefit under the Retirement Plan, the participant will automatically become fully vested in his benefit under the SERP and a benefit will be payable under the SERP. The term “change in control” has the same meaning in the SERP as in the Severance Plan and the Supplementary Severance Plan. See the discussion under “Change in Control Arrangements.”
During 2005, decisionsUnless otherwise provided in a participant agreement, the amount of any benefit payable to a participant under the SERP will be determined as of the date he or she first becomes eligible to receive benefits under the SERP, and will be equal to (i) the cash balance account that otherwise would have been payable under the Retirement Plan as of such determination date, based on various elements of executive compensation were madeand disregarding the limitations imposed by the Human Resources Committee. No officer, employee or former officerInternal Revenue Code on the amount of SCANA or anyannual retirement benefits payable to employees from qualified pension plans and on the amount of its subsidiaries servedannual compensation that may be taken into account for all qualified plan purposes, minus (ii) the participant’s cash balance account determined under the Retirement Plan as a memberof such determination date. For purposes of the Human Resources Committee.SERP, “compensation” is defined as determined under the Retirement Plan, without regard to the limitation under Section 401(a)(17) of the Internal Revenue Code, including any amounts of compensation otherwise deferred under any non-qualified deferred compensation plan (excluding the SERP).
The namesbenefit payable to a participant under the SERP will be paid, or commence to be paid, as of the persons who servefirst day of the calendar month following the date the participant first becomes eligible to receive a benefit under the SERP. With respect to amounts earned and vested before January 1, 2005, the participant may elect, in accordance with procedures we establish, to receive a distribution of such benefit in either of the following two forms of payment:
| · | A single sum distribution of the value of the participant’s benefit under the SERP determined as of the last day of the month preceding the date he or she first becomes eligible to receive benefits; or |
| · | A lifetime annuity benefit with an additional death benefit payment as follows: A lifetime annuity that is the actuarial equivalent of the participant’s single sum amount which provides for a monthly benefit payable for the participant’s life, beginning on the first day of the month following the date on which he or she first becomes eligible to receive benefits. In addition to this life annuity, commencing on the first day of the month following the participant’s death, his or her designated beneficiary will receive a benefit of 60% of the amount of the participant’s monthly payment continuing for a 15 year period. If, however, the beneficiary dies before the end of the 15 year period, the lump sum value of the remaining monthly payments of the survivor benefit will be paid to the beneficiary’s estate. The participant’s life annuity will not be reduced to reflect the “cost” of providing the 60% survivor benefit feature. “Actuarial equivalent” is defined by the SERP as equality in value of the benefit provided under the SERP based on actuarial assumptions, methods, factors and tables that would apply under the Retirement Plan under similar circumstances. |
For amounts earned and vested after January 1, 2005, the amounts are subject to Internal Revenue Service Code Section 409A and the choice between lump sum and annuity is not available. The new distribution options have not yet been determined.
Unless otherwise provided in a participant agreement, if a participant dies before the first day of the calendar month after he or she becomes eligible to receive benefits under the SERP, a single sum distribution equal to the value of the benefit that otherwise would have been payable under the SERP will be paid to the participant’s designated beneficiary as soon as administratively practicable following the participant’s death. With respect to SERP amounts earned and vested on or after January 1, 2005, the Human Resources Committee canavailable distribution options will be found at Item 12, Security Ownershiplimited in accordance with Section 409A of Certain Beneficial Owners and Management and Related Stockholder Matters.the Internal Revenue Code.
Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 29, 2006
The lump sum or annuity amounts that would have been payable under the SERP to each of our Named Executive Officers if they had become eligible for benefits as of December 29, 2006 are set forth below. Also set forth below are the payments that would be made to each Named Executive Officer’s designated beneficiary if the officer had died December 29, 2006.
For Mr. Timmerman, the lump sum amount would have been $2,216,155, or the monthly payments would have been $13,536 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $8,121 for up to 15 years. If Mr. Timmerman had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.
For Mr. Addison, the lump sum amount would have been $85,796, or the monthly payments would have been $417 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $250 for up to 15 years. If Mr. Addison had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.
For Mr. Marsh, the lump sum amount would have been $435,636, or the monthly payments would have been $2,264 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $1,359 for up to 15 years. If Mr. Marsh had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.
For Mr. Mood, the lump sum amount would have been $54,862, or the monthly payments would have been $420 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $252 for up to 15 years. If Mr. Mood had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.
Mr. Bouknight was not vested so no payments would have been due.
For Mr. Byrne, the lump sum amount would have been $216,129, or the monthly payments would have been $1,062 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $637 for up to 15 years. If Mr. Byrne had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.
Executive Deferred Compensation Plan
The SCANA Corporation Executive Deferred Compensation Plan is described in the narrative following the 2006 Nonqualified Deferred Compensation table. As discussed in that section, amounts deferred under the plan are required to be paid, or begin to be paid, as soon as practicable following a participant’s death, disability, retirement or other termination of employment. Such payments are made in the form of a single sum cash distribution. However, at the election of the participant, payments payable after the participant’s death after reaching retirement age, retirement, or termination of employment as a result of disability, may be made in the form of annual installment payments over a period not to exceed 15 years. The plan defines “retirement age” as the later of reaching age 55 and 20 years of vesting service or attainment of age 65, and defines “retirement” as termination of employment after reaching retirement age. All amounts credited to a participant’s special ledger account continue to be hypothetically invested among the investment alternatives until such amounts are paid in full to the participant or his or her beneficiary. The terms of the plan governing distributions and deferrals are subject to further modification to conform to the requirements of Section 409A of the Internal Revenue Code.
The “Aggregate Balance at Last FYE” column of the 2006 Nonqualified Deferred Compensation table shows the amounts that would have been payable under the Executive Deferred Compensation Plan to each of our Named Executive Officers if they had died after reaching retirement age, retired, or if their employment had been terminated as a result of disability, as of December 29, 2006, and if they had been paid using the single sum form of payment. If the Named Executive Officers instead chose payment of the deferrals in annual installments, the installment payments over the payment periods selected by the Named Executive Officers are estimated as set forth below: Mr. Timmerman - $530,522; Mr. Addison - $65,020; Mr. Marsh - $221,068; Mr. Mood - 13,707; Mr. Bouknight - $12,516; Mr. Byrne - $87,834.
Director CompensationDIRECTOR COMPENSATION
Board Fees
TheOur Board reviews Directordirector compensation annuallyevery year with guidance from the Nominating and Governance Committee. In making its recommendations, the committeeCommittee is required by SCANA’sSCANA's Governance Principles to consider that compensation should fairly pay Directorsdirectors for work required in a company of SCANA’sSCANA's size and scope, compensation should align Directors’directors' interests with the long-term interests of shareholders, and the compensation structure should be transparent and easy for shareholders to understand. We also consider the risk inherent in board service. Every other year the Nominating Committee considers relevant public data in making recommendations.
Officers who are also Directorsdirectors do not receive additional compensation for their service as Directors.directors. All Directorsdirectors of SCANA also serve as Directorsdirectors of SCE&G without additional compensation. Effective January 1, 2005, compensation for non-employee Directorsdirectors consists of the following:
| · | an annual retainer of $45,000;$45,000 (required to be paid in shares of SCANA's common stock effective January 1, 2006); |
| · | a fee of $6,500 for attendance at a regular quarterly meetingmeetings of the boardBoard of directors;Directors; |
| · | a fee of $6,000 for attendance at all-day meetings of the boardBoard of directorsDirectors other than regular meetings; |
| · | a fee of $3,000 for attendance at half-day meetings of the Board 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 boardBoard of directorsDirectors or a committee that last fewer than 30 minutes; |
| · | a fee of $600 for telephonic meetings of the boardBoard of directorsDirectors or a committee that last more than 30 minutes; and |
| · | reimbursement of reasonable expenses incurred in connection with all of the above. |
Unless deferred at the director’s election pursuant to the terms of the SCANA Director Compensation and Deferral Plan, directors’ retainer fees are paid annually in shares of SCANA's common stock, and meeting attendance and conference fees are paid at such times as the Board determines in cash or SCANA common stock at the director’s election.
Director Compensation and Deferral Plans
Since January 1, 2001, our non-employee director compensation and related deferrals have been governed by the SCANA Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2005,2006, the only director with funds remaining in the SCANA Voluntary Deferral Plan was Mr. Bennett, whose account was credited with interest of $4,345.26 for the year.Bennett.
Under the SCANA Director Compensation and Deferral Plan, a director may electmake an annual irrevocable election to defer the annual retainer fee, which (effective January 1, 2006) is required to be paid in 100% SCANASCANA's common stock, in a hypothetical investment in SCANASCANA's common stock, with distribution from the plan to be ultimately payable in actual shares of SCANASCANA's 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 SCANASCANA's common stock or cash. Amounts payable in SCANASCANA's common stock accrue earnings during the deferral period at SCANA'sour dividend rate, which amountdirectors may be electedchoose to behave paid in cash when accrued or retained to invest in additional hypothetical shares of SCANASCANA's common stock. Amounts payable in cash accrue interest until paid. Hypothetical shares do not have voting rights.
During 2005,2006, Messrs. Amick, Bennett, Burkhardt, Sloan, and York and Ms. Miller elected to defer 100% of their
compensation and earnings and Messrs. Hagood and Stowe deferred a portion of their earnings under the SCANA Director Compensation and Deferral Plan so asPlan.
As previously discussed, we plan to acquire hypothetical sharesamend all available distribution and withdrawal options with respect to amounts earned or vested after 2004 under all of SCANA common stock.the deferred compensation plans to conform to the requirements for deferred compensation under Section 409A of the Internal Revenue Code.
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 SCANAus 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'sour commitment to quality higher education and to enhance itsour ability to attract and retain qualified Boardboard members. A portion is contributed upon retirement of the director and the remainder upon the director's death. As of December 31, 2006, our obligation under the plan was $4,462,356. The plan is funded in part through insurance policies on the lives of the directors. The 2006 premium for such insurance was $333,928 which was offset by the receipt of insurance proceeds in the amount of $754,498. The insurance proceeds were received in 2006 after the death of a director in 2005. Currently the premium estimate for 2007 is $95,000.
Designated institutions of higher education in South Carolina, North Carolina and Georgia must be approved by SCANA's Chief Executive Officer. Institutions in other states must be approved by the Human Resources Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the plan.
2006 DIRECTOR COMPENSATION
The following table sets forth the compensation we paid to each of our non-employee directors in 2006.
| Name | | Fees Earned or Paid in Cash ($) | | Stock Awards ($)(1) | | Option Awards ($) | | Non-Equity Incentive Plan Compensation ($) | | Change in Pension Value and Nonqualified Deferred Compensation Earnings(2) ($) | | All Other Compensation ($) | | Total ($) | |
| (a) | | | (b | ) | | (c | ) | | (d | ) | | (e | ) | | (f | ) | | (g | ) | | (h | ) |
B. L. Amick | | $ | 43,500 | | $ | 45,000 | | | | | | | | | | | | | | | | |
J. A. Bennett | | $ | 71,000 | | $ | 45,000 | | | | | | | | $ | 3,830 | | | | | | | |
W. C. Burkhardt | | $ | 75,800 | | $ | 45,000 | | | | | | | | | | | | | | | | |
S. A. Decker | | $ | 77,600 | | $ | 45,000 | | | | | | | | | | | | | | | | |
D. M. Hagood | | $ | 73,400 | | $ | 45,000 | | | | | | | | | | | | | | | | |
W. H. Hipp | | $ | 38,000 | | $ | 45,000 | | | | | | | | | | | | | | | | |
L. M. Miller | | $ | 81,800 | | $ | 45,000 | | | | | | | | | | | | | | | | |
M. K. Sloan | | $ | 76,400 | | $ | 45,000 | | | | | | | | | | | | | | | | |
H. C. Stowe | | $ | 57,900 | | $ | 45,000 | | | | | | | | | | | | | | | | |
G. S. York | | $ | 68,000 | | $ | 45,000 | | | | | | | | | | | | | | | | |
(1)The annual retainer of $45,000 is required to be paid in SCANA's common stock. Shares were purchased on January 12, 2006 at a weighted average purchase price of $40.46 in order to satisfy the retainer fee obligation.
(2)Mr. Bennett is the only Director who elected to defer director fees into a cash deferral account. Pursuant to the terms of the deferral plan, the earnings are above market as defined by the rules. The amounts shown above represent Mr. Bennett’s above-market earnings on his deferrals into the cash deferral account ($2,404) as well as his earnings on prior cash deferrals into the prior SCANA Voluntary Deferral Plan ($1,426).
RELATED STOCKHOLDER MATTERS
SCANA: Information called forrequired by this Item 12 is incorporated herein by reference to the caption "Share Ownership of Directors, Nominees and Executive Officers" and "Five Percent Ownership of SCANA Common Stock""SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" in SCANA's definitive proxy statement for the 20062007 annual meeting of shareholders.
Equity securities issuable under SCANA's compensation plans at December 31, 20052006 are summarized as follows:
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
| | (a) | (b) | (c) | (a) | (b) | (c) |
| Equity compensation plans approved by security holders: | | | | | |
| Long-Term Equity Compensation Plan | 432,970 | $27.53 | 3,210,827 | 385,940 | 27.56 | 3,210,827 |
| Non-Employee Director Compensation Plan | n/a | n/a | 122,566 | n/a | 113,883 |
| Equity compensation plans not approved by security holders | n/a | n/a | n/a | n/a | n/a |
| Total | 432,970 | $27.53 | 3,333,393 | 385,940 | 27.56 | 3,324,710 |
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, 20062007 by each director and each person named in the Summary Compensation table in Item 11, Executive Compensation.11. EXECUTIVE COMPENSATION.
Name of Beneficial Owner | Amount and Nature of Beneficial Ownership(1) (2) (3) (4) (5) | Percent of Class |
| W. B. Timmerman | 61,090 | * |
| J. E. Addison | 14,040 | * |
| K. B. Marsh | 19,156 | * |
| F. P. Mood, Jr. | 1,568 | * |
| J. C. Bouknight | 1,540 | * |
| S. A. Byrne | 31,467(3) | * |
| B. L. Amick | 11,669 | * |
| J. A. Bennett | 3,808 | * |
| W.C. Burkhardt | 13,122 | * |
| S. A. Decker | 2,205 | * |
| D. M. Hagood | 1,541 | * |
| W. H. Hipp | 15,773 | * |
| L. M. Miller | 3,738 | * |
| M. K. Sloan | 1,910 | * |
| H. C. Stowe | 2,850 | * |
| G. S. York | 13,770 | * |
| All executive officers and directors as a group (18 persons) | 222,076(6) | * |
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 lessLess 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, 2006,2007, 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. |
(2)Hypothetical shares acquired under the Director Compensation and Deferral Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 22, 2007, each of the following directors had acquired under the plan the number of hypothetical shares following his or her name: Messrs. Amick 15,575; Bennett 13,736; Burkhardt 18,594; Hagood 5,378; Hipp 12,022; Sloan 17,776; Stowe 13,146; and York 17,927; Mrs. Decker 0; and Ms. Miller 18,823.
(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. |
(3)Includes shares subject to options that are currently exercisable or that will become exercisable within 60 days in the following amounts: Mr. Byrne 21,492.
(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. |
(4)Hypothetical shares acquired under the Executive Deferred Compensation Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 22, 2007, each of the following officers had acquired under the plan the number of hypothetical shares following his name: Messrs. Timmerman 41,964; Addison 654; Marsh 5,157; Mood 0; Bouknight 0; and Byrne 8,368.
(6) | Indicates a member of the Human Resources Committee. |
(5)Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or named executive officer, as follows: Mr. Amick-480. Also includes 2,000 shares held in a trust for the benefit of a family member of Mr. Timmerman, of which Mr. Timmerman serves as Trustee. (6)Includes a total of 21,492 shares subject to options that are currently exercisable or that will become exercisable within 60 days.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not ApplicableRelated Transactions
We require that each senior executive officer, director and director nominee complete an annual questionnaire and report all transactions with SCANA and any of its subsidiaries, including SCE&G, in which such persons (or their immediate family members) had or will have a direct or indirect material interest (except for salaries, directors’ fees and dividends on SCANA stock). Our General Counsel reviews responses to the questionnaires, and if any such transactions are disclosed, they are reviewed by the Nominating Committee, and if appropriate, submitted to the Board for approval. The Company does not, however, have a formal written policy or procedure for approval or ratification of such transactions.
The types of transactions that have been reviewed in the past include the purchase and sale of goods, services or property from companies for which our directors serve as executive officers or directors, the purchase of financial services and access to lines of credit from banks for which our directors serve as executive officers or directors, and the employment of family members of executive officers or directors. There were no such transactions during the year ended December 31, 2006.
Each of the directors listed in Item 10 is “independent”, as defined in the New York Stock Exchange Listing Standards, except William B. Timmerman.
ITEM 14. 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
SCANA: The information required by Item 14 is incorporated herein by reference to "Proposal"PROPOSAL 2 - Approval of Appointment of Independent Registered Public Accounting Firm"APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM" in SCANA's definitive proxy statement for the 20062007 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 billedcharged to SCE&G and PSNC Energy for the fiscal years ended December 31, 20052006 and 20042005 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.
| | | 2005 | | 2004 | | | SCE&G | |
| | | SCE&G | | PSNC Energy | | SCE&G | | PSNC Energy | | | 2006 | | 2005 | |
| Audit Fees(1) | | $ | 1,389,564 | | $ | 268,441 | | $ | 1,380,354 | | $ | 284,512 | | | $ | 1,424,242 | | | $ | 1,389,564 | |
| Audit-Related Fees(2) | | | 50,073 | | | 10,793 | | | 70,565 | | | 6,240 | | | | 42,471 | | | | 50,073 | |
| Tax Fees(3) | | | 51,727 | | | 3,968 | | | 2,582 | | | 535 | | | | 58,672 | | | | 51,727 | |
| All Other Fees | | | - | | | - | | | - | | | - | | |
| Total Fees | | $ | 1,491,364 | | $ | 283,202 | | $ | 1,453,501 | | $ | 291,287 | | | $ | 1,523,385 | | | $ | 1,491,364 | |
| (1) | Fees for audit services billed in 20052006 and 20042005 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. |
(2)Fees primarily for employee benefit plan audits for 2006 and 2005.
(3) | Fees for tax compliance and tax research services. |
(3)Fees for tax compliance and tax research services.
| In 2006 and 2005, and 2004, all of the Audit Fees, Audit Related Fees and Tax Fees were approved by the Audit Committee. |
PART IV
ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed or furnished as a part of this Form 10-K:
(1) Financial Statements and Schedules:
The Report of Independent Registered Public Accounting Firm on the financial statements for SCANA and SCE&G and PSNC Energy are listed under Item 8 herein.
The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G and PSNC Energy are listed under Item 8 herein.
The financial statement schedules filed as part of this report for SCANA and 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 (SEC) and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.
Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA's employee stock purchase plan will be furnished under cover of Form 10-K/A to the CommissionSEC when the information becomes available.
As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries and of SCE&G, for itself and its consolidated affiliates, and of PSNC Energy, for itself and its subsidiaries, have been omitted and SCANA and SCE&G and PSNC Energy agree to furnish a copy of such instruments to the CommissionSEC upon request.
Schedule II—Valuation and Qualifying Accounts
| | Additions | | | | | Additions | | | | | |
Description | Beginning Balance | Charged to Income | Charged to Other Accounts | Deductions from Reserves | Ending Balance | | 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 | | | | | | | | | | | | | | |
| 2006 | | | $ | 24,863,825 | | $ | 16,935,990 | | - | | $ | 27,811,236 | | $ | 13,988,579 | |
| 2005 | 15,740,636 | 26,705,178 | - | 17,581,989 | 24,863,825 | | | 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 | | | 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 | | | | | | | | | | | | | | | |
| 2006 | | | | - | | - | | - | | - | | - | |
| 2005 | - | - | - | | | - | | - | | - | | - | | - | |
| 2004 | 125,000 | - | 125,000 | - | | $ | 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 | | | | | | | | | | | | | | | |
| 2006 | | | $ | 6,328,361 | | $ | 6,734,385 | | $ | 400,895 | | $ | 4,434,867 | | $ | 9,028,774 | |
| 2005 | 8,121,122 | 6,038,014 | - | 7,830,775 | 6,328,361 | | | 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 | | | 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 | | | | | | | | | | | | | | | |
| 2006 | | | $ | 1,574,069 | | $ | 7,481,886 | | - | | $ | 3,854,788 | | $ | 5,201,167 | |
| 2005 | 1,182,064 | 3,518,845 | - | 3,126,840 | 1,574,069 | | | 1,182,064 | | 3,518,845 | | - | | 3,126,840 | | 1,574,069 | |
| 2004 | 951,176 | 2,891,370 | - | 2,660,482 | 1,182,064 | | | 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 | | | | | | | | | | | | | | | |
| 2006 | | | $ | 4,892,076 | | $ | 5,980,520 | | - | | $ | 3,964,279 | | $ | 6,908,317 | |
| 2005 | 5,749,088 | 3,378,138 | - | 4,235,150 | 4,892,076 | | | 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 | | | 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 | |
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, 20062007 |
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. MarshJ. E. Addison K. B. Marsh,J. E. Addison, Senior Vice President
and Chief Financial Officer (Principal Financial Officer) |
| | /s/J. E. Swan, IV J. E. Swan, IV, Controller (Principal Accounting Officer) |
| Other Directors*: | | |
| | B. L. Amick | | 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,Jimmy E. Addison, Attorney-in-Fact
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. LorickK. B. Marsh N. O. LorickK. B. Marsh
President and Chief Operating Officer |
| | DATE: | March 1, 20062007 |
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. MarshJ. E. Addison K. B. Marsh,J. E. Addison, Senior Vice President
and Chief Financial Officer (Principal Financial Officer) |
| | | /s/J. E. Swan, IV J. E. Swan, IV, Controller (Principal Accounting Officer) |
| Other Directors*: | | |
| | B. L. Amick | | 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,Jimmy E. Addison, Attorney-in-Fact
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
| | 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 |
| | | | February 26, 2004 | Exhibit 3.05 | to Form 10-K for the year ended December 31, 2004 |
| | | | 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 |
| | | | March 14, 2006 | Exhibit 3.01 | to Form 8-K dated March 17, 2006 |
| | | May 11, 2006 | Exhibit 3.01 | to Form 8-K filed May 15, 2006 |
| | | June 28, 2006 | Exhibit 3.01 | to Form 8-K filed June 29, 2006 |
| | | August 16, 2006 | Exhibit 3.01 | to Form 8-K filed August 17, 2006 |
| | | | | |
| 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) |
3.073.06 | | 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 | |
| | | August 12, 2002 | Exhibit 3.13 | |
| | 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 | |
| | | | | |
3.083.07 | | X | Articles of Correction dated March 17, 2006, correcting March 14, 2006 Articles of Amendment (Filed as Exhibit 3.02 to Form 8-K dated March 17, 2006 and incorporated by reference herein) |
| 3.08 | | X | Articles of Correction dated September 6, 2006, correcting August 16, 2006 Articles of Amendment (Filed as Exhibit 3.01 to Form 8-K filed September 7, 2006 and incorporated by reference herein) |
| 3.09 | X | | By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein) |
3.093.10 | | X | | By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein) |
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 |
| 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) |
4.074.04 | X | X | | First Supplemental Indenture to Indenture referred to in Exhibit 4.064.03 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein) |
4.084.05 | X | X | | Second Supplemental Indenture to Indenture referred to in Exhibit 4.064.03 dated as of June 15, 1993 (Filed (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) |
| 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(filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and incorporated by reference herein) |
| *10.02 | X | X | Amendment to SCANA Executive Deferred Compensation Plan as adopted December 20, 2005 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 2006 and incorporated by reference herein) |
| *10.03 | X | X | Amendments to SCANA Executive Deferred Compensation Plan as adopted on November 1, 2006 (Filed herewith) |
| *10.04 | X | X | SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by reference herein) |
*10.03 | XApplicable to Form 10-K of | X |
Exhibit No. | XSCANA | SCE&G | Description |
*10.05 | X | X | Amendment to SCANA Director Compensation and Deferral Plan as adopted April 29, 2004December 20, 2005 (Filed as Exhibit 10.0310.01 to Form 10-Q for the quarter ended March 31, 20042006 and incorporated by reference herein) |
*10.0410.06 | X | X | X | AmendmentAmendments to SCANA Director Compensation and Deferral Plan as adopted on November 2, 20051, 2006 (Filed herewith) |
| *10.07 | X | X | SCANA Supplemental Executive Retirement Plan as amended and restated as of July 1, 2000 (Filed as Exhibit 10.03a10.04 to Form 10-Q for the quarter ended September 30, 20052006 and incorporated by reference herein) |
*10.0510.08 | X | X | X | Amendments to the SCANA SupplementarySupplemental Executive Retirement Plan as amended Julyadopted on November 1, 20012006 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)herewith) |
*10.06 | X10.09 | X | X | SCANA Key Executive Severance Benefits Plan as amended and restated as of July 1, 2001 (Filed as Exhibit 10.0310.05 to Form 10-Q for the quarter ended September 30, 20012006 and incorporated by reference herein) |
*10.0710.10 | X | X | Amendments to the SCANA Key Executive Severance Benefits Plan as adopted on November 1, 2006 (Filed herewith) |
| *10.11 | X | X | SCANA Supplementary Key Executive Severance Benefits Plan as amended and restated as of July 1, 2001 (Filed as Exhibit 10.03a10.06 to Form 10-Q for the quarter ended September 30, 20012006 and incorporated by reference herein) |
*10.0810.12 | X | X | Amendments to the SCANA Supplementary Key Executive Severance Benefits Plan as adopted on November 1, 2006 (Filed herewith) |
| *10.13 | X | X | SCANA Executive Benefit Plan as established effective as of July 1, 2001 (Filed herewith) |
| *10.14 | X | X | Amendments to the SCANA Executive Benefit Plan as adopted on November 1, 2006 (Filed herewith) |
| *10.15 | X | X | SCANA Supplementary Executive Benefit Plan as established effective as of July 1, 2001 (Filed herewith) |
| *10.16 | X | X | Amendments to the SCANA Supplementary Executive Benefit Plan as adopted on November 1, 2006 (filed herewith) |
| *10.17 | X | X | SCANA Long-Term Equity Compensation Plan datedas amended and restated as of January 20001, 2005 (Filed as Exhibit 4.0410.01 to Registration Statement No. 333-37398Form 8-K dated May 5, 2005 and incorporated by reference herein) |
*10.09*10.18 | 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) |
| Applicable to Form 10-K of
| |
Exhibit
No.
| SCANA
| SCE&G
| PSNC
Energy
| Description
|
*10.1110.19 | 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) |
*10.1210.20 | X | X | X | Description of AmendmentAmendments to SCANA Corporation ExecutiveShort-Term Annual Incentive Plan as adopted on November 1, 2006 (Filed on Form 8-K dated February 23, 2005 and incorporated by reference herein)herewith) |
10.13 | 10.21 | | 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) |
| | Applicable to Form 10-K of | |
Exhibit No. | SCANA | SCE&G | PSNC
Energy
| Description | | |
| | | | |
| *10.22 | X | | Independent contractor agreement with Neville O. Lorick (Filed as Exhibit 99.1 to Form 8-K filed June 15, 2006 and incorporated by reference herein) |
| 12.01 | X | | Statement Re Computation of Ratios |
| 12.02 | | 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) |
| 24.01 | X | X | Power of Attorney (Filed herewith) |
| 31.01 | X | | Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) |
| 31.02 | X | | | Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) |
| 31.03 | | X | | Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) |
| 31.04 | | X | | Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) |
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
