ITEM 1. BUSINESS
CORPORATE STRUCTURE
SCANA Corporation (SCANA), a holding company, owns the following direct, wholly-owned subsidiaries;
South Carolina Electric & Gas Company (SCE&G) is engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers and the purchase, sale and transportation of natural gas to retail customers.
South Carolina Generating Company, Inc. (GENCO) owns Williams Station and sells electricity solely to SCE&G.
South Carolina Fuel Company, Inc. (Fuel Company) acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances.
Public Service Company of North Carolina, Incorporated (PSNC Energy) purchases, sells and transports natural gas to retail customers.
Carolina Gas Transmission Corporation (CGT) transports natural gas in South Carolina and southeastern Georgia.
SCANA Communications, Inc. (SCI) provides fiber optic communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia.
SCANA Energy Marketing, Inc. (SEMI) markets natural gas, primarily in the Southeast, and provides energy-related risk management services. SCANA Energy, a division of SEMI, markets natural gas in Georgia’s retail market.
ServiceCare, Inc. provides service contracts on home appliances and heating and air conditioning units.
SCANA Services, Inc. provides administrative, management and other services to SCANA’s subsidiaries and business units.
SCANA is incorporated in South Carolina, as is each of its direct, wholly-owned subsidiaries. In addition to the subsidiaries above, SCANA owns three other energy-related companies that are insignificant and one additional company that is in liquidation.
ORGANIZATION
SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA holds, directly or indirectly, all of the capital stock of each of its subsidiaries. SCANA and its subsidiaries had full-time, permanent employees as of February 20, 2010 and 2009 of 5,828 and 5,786, respectively. SCE&G is an operating public utility incorporated in 1924 as a South Carolina corporation. SCE&G had full-time, permanent employees as of February 20, 2010 and 2009 of 3,108 and 3,086, respectively.
INVESTOR INFORMATION
SCANA’s and SCE&G’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with or furnished to the SEC are available free of charge through SCANA’s internet website at www.scana.com as soon as reasonably practicable after these reports are filed or furnished. Information on SCANA’s website is not part of this or any other report filed with or furnished to the SEC.
SEGMENTS OF BUSINESS
For information with respect to major segments of business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 12). All such information is incorporated herein by reference.
SCANA does not directly own or operate any significant physical properties. SCANA, through its subsidiaries, is engaged in the functionally distinct operations described below.
Regulated Utilities
SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 655,000 customers and the purchase, sale and transportation of natural gas to approximately 310,000 customers (each as of December 31, 2009). SCE&G’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers more than 25,000 square miles. More than 3.2 million persons live in the counties where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries served by SCE&G include chemicals, educational services, textile manufacturing, paper products, food products, lumber and wood products, health services, food and retail stores.
GENCO owns Williams Station and sells electricity solely to SCE&G.
Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances.
PSNC Energy purchases, sells and transports natural gas to approximately 473,000 residential, commercial and industrial customers (as of December 31, 2009). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The industrial customers of PSNC Energy include manufacturers and processors of automobiles, pharmaceuticals, biotechnicals, chemicals, ceramics, food products, steel and non-woven textile and kindred products.
CGT operates as an open access, transportation-only interstate pipeline company regulated by FERC. CGT operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGT also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transco in Cherokee and Spartanburg counties, South Carolina. CGT’s customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SEMI (which markets natural gas to industrial and sale for resale customers, primarily in the Southeast), other natural gas utilities, municipalities, county gas authorities, and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles.
Nonregulated Businesses
SEMI markets natural gas primarily in the southeast and provides energy-related risk management services. SCANA Energy, a division of SEMI, sells natural gas to over 455,000 customers (as of December 31, 2009) in Georgia’s natural gas market. The Georgia Public Service Commission (GPSC) has selected SCANA Energy to serve as the state’s regulated provider until August 31, 2011. Included in the above customer count, SCANA Energy serves over 90,000 customers (as of December 31, 2009) under this regulated provider contract, which includes low-income and high credit risk customers. SCANA Energy’s total customer base represents an approximately 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.
SCI owns and operates a 500-mile fiber optic telecommunications network and ethernet network and data center facilities in South Carolina. Through a joint venture, SCI has an interest in an additional 2,280 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides tower site construction, management and rental services in South Carolina and North Carolina.
The preceding Corporate Structure section describes other businesses owned by SCANA.
COMPETITION
For a discussion of the impact of competition, see the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
CAPITAL REQUIREMENTS
SCANA’s regulated subsidiaries, including SCE&G, require cash to fund operations, construction programs and dividend payments to SCANA. SCANA’s nonregulated subsidiaries require cash to fund operations and dividend payments to SCANA. To replace existing plant investment and to expand to meet future demand for electricity and gas, SCANA’s regulated subsidiaries must attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, when requested.
For a discussion of various rate matters and their impact on capital requirements, see the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 2 to the consolidated financial statements for SCANA and SCE&G.
During the period 2010-2012, SCANA and SCE&G expect to meet capital requirements through internally generated funds, issuance of equity and short-term and long-term borrowings. SCANA and SCE&G expect that they have or can obtain adequate sources of financing to meet their projected cash requirements for the next 12 months and for the foreseeable future.
For a discussion of cash requirements for construction and nuclear fuel expenditures, contractual cash obligations, financing limits, financing transactions and other related information, see the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCANA’s ratios of earnings to fixed charges were 2.84, 3.04, 3.03, 2.94 and 2.19 for the years ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively. SCE&G’s ratios of earnings to fixed charges were 3.25, 3.51, 3.40, 3.32 and 2.26 for the same periods. SCANA’s and SCE&G’s ratios for 2005 were negatively impacted by large amounts of accelerated depreciation that were recorded under an accounting methodology approved by the Public Service Commission of South Carolina (SCPSC), and because the calculations necessarily exclude the related and fully offsetting synthetic fuel tax benefits recorded in that year.
ELECTRIC OPERATIONS
Electric Sales
SCE&G’s sales of electricity by customer classification as a percent of electric revenues for 2008 and 2009 were as follows:
SCE&G’s margins earned from the sale of electricity by customer classification as a percent of electric margin for 2008 and 2009 were as follows:
Sales for resale include sales to six municipalities. Sales under NMST during 2009 include sales to nine investor-owned utilities or registered marketers, three electric cooperatives and three federal/state electric agencies. During 2008 sales under the NMST included sales to 13 investor-owned utilities or registered marketers, four electric cooperatives and four federal/state electric agencies.
During 2009 SCE&G recorded a net increase of approximately 5,200 electric customers (growth rate of 0.8%), increasing its total electric customers to approximately 655,000 at year end.
For the period 2010-2012, SCE&G projects total territorial KWh sales of electricity to increase 1.4% annually (assuming normal weather), total electric customer base to increase 2.1% annually and territorial peak load (summer, in MW) to increase 1.7% annually. While SCE&G’s goal is to maintain a reserve margin of between 12% and 18%, weather and other factors affect territorial peak load and can cause actual generating capacity on any given day to fall below the reserve margin goal.
Electric Interconnections
SCE&G purchases all of the electric generation of GENCO’s Williams Station under a Unit Power Sales Agreement which has been approved by FERC. Williams Station has a net generating capacity (summer rating) of 570 MW.
SCE&G’s transmission system is part of an interconnected grid extending over a large part of the southern and eastern portions of the nation. SCE&G interconnects with Duke Energy Carolinas, Progress Energy Carolinas, and Santee Cooper. SCE&G also interconnects with Georgia Power Company, Oglethorpe Power Corporation and the Southeastern Power Administration’s Clarks Hill Project. SCE&G, Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Dominion Virginia Power and ALCOA Power Generating, Inc. (Yadkin Division), are members of the Virginia-Carolinas Reliability Group (VACAR), one of several geographic divisions within the SERC Reliability Corporation (SERC). SERC is one of eight regional entities with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing reliability standards approved by NERC within the SERC region. SERC is divided geographically into five diverse sub-regions that are identified as Central, Delta, Gateway, Southeastern and VACAR. The regional entities and all members of NERC work to safeguard the reliability of the bulk power systems throughout North America. For a discussion of the impact certain legislative and regulatory initiatives may have on SCE&G’s transmission system, see Electric Operations within the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
Fuel Costs and Fuel Supply
The average cost of various fuels and the weighted average cost of all fuels (including oil) for the years 2007-2009 follow:
The sources and percentages of total MWh generation by each category of fuel for the years 2007-2009 and the estimates for the years 2010-2012 follow:
Six of the seven fossil fuel-fired plants use coal. Unit trains and, in some cases, trucks and barges deliver coal to these plants.
As coal costs increased and gas prices decreased during 2009, SCE&G’s mix of generation dispatched shifted.
Coal is obtained through long-term supply contracts and spot market purchases. Long-term contracts exist with 11 suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 5.6 million tons annually, which is 98% of total expected coal purchases for 2010. Sulfur restrictions on the contract coal range from 1% to 2%. These contracts expire at various times through 2012. Spot market purchases are expected to continue when needed or when prices are believed to be favorable.
SCANA and SCE&G believe that SCE&G’s operations comply with all existing regulations relating to the discharge of sulfur dioxide and nitrogen oxides. See additional discussion at Environmental Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCE&G has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station Unit 1 through 2016. The following table summarizes contract commitments for the stages of nuclear fuel assemblies:
Commitment
Contractor
Remaining Regions(a)
Expiration Date
Uranium
United States Enrichment Corporation
22-25
Enrichment
United States Enrichment Corporation
22-30
Fabrication
Westinghouse Electric Corporation
(a) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region 21 was loaded
in 2009.
SCE&G can store spent nuclear fuel on-site until at least 2018 and expects to expand its storage capacity to accommodate the spent fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available. In addition, Summer Station has sufficient on-site storage capacity to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract with the DOE regarding disposal of spent fuel, see Hazardous and Solid Wastes within the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
GAS OPERATIONS
Gas Sales-Regulated
Regulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 2008 and 2009 were as follows:
For the three-year period 2010-2012, SCANA projects total consolidated sales of regulated natural gas in DTs to increase 1.4% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 2.1%, commercial of 1.1% and industrial of 1.8%.
For the three-year period 2010-2012, SCE&G projects total consolidated sales of regulated natural gas in DTs to increase 1.4% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 0.2%, commercial of 0.3% and industrial of 3.2%.
For the three-year period 2010-2012, SCANA’s and SCE&G’s total consolidated regulated natural gas customer base is projected to increase annually 2.4% and 1.2%, respectively. During 2009 SCANA recorded a net increase of approximately 7,700 regulated gas customers (growth rate of 1.0%), increasing its regulated gas customers to approximately 782,000. Of this increase, SCE&G recorded a net increase of approximately 2,600 gas customers (growth rate of 0.9%), increasing its total gas customers to approximately 310,000 (as of December 31, 2009).
Demand for gas changes primarily due to the effect of weather and the price relationship between gas and alternate fuels.
Gas Cost, Supply and Curtailment Plans
South Carolina
SCE&G purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. The gas is delivered to South Carolina through firm transportation agreements with Southern Natural (expiring in 2012), Transco (expiring in 2012 and 2017) and CGT (expiring in 2011 and 2012). The maximum daily volume of gas that SCE&G is entitled to transport under these contracts is 161,144 DT from Southern Natural, 64,652 DT from Transco and 314,529 DT from CGT. Additional natural gas volumes may be delivered to SCE&G’s system as capacity is available through interruptible transportation. In addition, SCE&G, under contract with SEMI, is entitled to receive up to a daily contract demand of 120,000 DT for use in either electric generation or for resale to SCE&G’s customers.
The daily volume of gas that SEMI is entitled to transport under its service agreement with CGT (expiring in 2023) on a firm basis is 198,083 DT.
SCE&G purchased natural gas at an average cost of $7.01 per MCF during 2009 and $10.50 per MCF during 2008.
SCE&G was allocated 5,437 MMCF of natural gas storage capacity on Southern Natural and Transco. Approximately 4,100 MMCF of gas were in storage on December 31, 2009. To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCE&G supplements its supplies of natural gas with two LNG liquefaction and storage facilities. The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately 1,800 MMCF (liquefied equivalent) of gas were in storage on December 31, 2009.
North Carolina
PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at current prices and on a long-term basis for reliability assurance at index prices plus a reservation charge. Transco and Dominion deliver the gas to North Carolina through transportation agreements with expiration dates ranging through 2016. On a peak day, PSNC Energy may transport daily volumes of gas under these contracts on a firm basis of 259,894 DT from Transco and 7,331 DT from Dominion.
PSNC Energy purchased natural gas at an average cost of $6.02 per DT during 2009 compared to $10.65 per DT during 2008.
To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and LNG peaking services. Underground natural gas storage service agreements with Dominion, Columbia Gas Transmission, Transco and Spectra Energy provide for storage capacity of approximately 13,000 MMCF. Approximately 9,300 MMCF of gas were in storage under these agreements at December 31, 2009. In addition, PSNC Energy’s LNG facility can store the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day. Approximately 900 MMCF (liquefied equivalent) of gas were in storage at December 31, 2009. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,100 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2009.
SCANA and SCE&G believe that supplies under long-term contracts and supplies available for spot market purchase are adequate to meet existing customer demands and to accommodate growth.
Gas Marketing-Nonregulated
SEMI markets natural gas and provides energy-related risk management services primarily in the Southeast. In addition, SCANA Energy, a division of SEMI, markets natural gas to over 455,000 customers (as of December 31, 2009) in Georgia’s natural gas market. SCANA Energy’s total customer base represents an approximately 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.
Risk Management
SCANA and SCE&G have established policies and procedures and risk limits to control the level of market, credit, liquidity and operational and administrative risks assumed by them. SCANA's Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and to oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including a Risk Management Officer and several senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
REGULATION
SCANA is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters and is subject to the jurisdiction of the United States Federal Energy Regulatory Commission (FERC) as to certain acquisitions and other matters.
SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.
GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.
PSNC Energy is subject to the jurisdiction of the North Carolina Utilities Commission (NCUC) as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.
CGT is subject to the jurisdiction of FERC as to transportation rates, service, accounting and other matters.
SCANA Energy is regulated by the GPSC through its certification as a natural gas marketer in Georgia and specifically is subject to the jurisdiction of the GPSC as to retail prices for customers served under the regulated provider contract.
SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting. See the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of such short-term indebtedness. The authority to make such issuances will expire on February 5, 2012.
SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The licenses expire as follows:
The current license for the Saluda project expires August 31, 2010. SCE&G applied to FERC for relicensing of the Saluda project on August 27, 2008. This application is currently being reviewed by FERC. SCE&G expects a decision by FERC in August 2010.
At the termination of a license under the Federal Power Act, FERC may extend or issue a new license to the previous licensee, may issue a license to another applicant or the federal government may take over the related project. If the federal government takes over a project or if FERC issues a license to another applicant, the federal government or the new licensee, as the case may be, must pay the previous licensee an amount equal to its net investment in the project, not to exceed fair value, plus severance damages.
For a discussion of legislative and regulatory initiatives being implemented that will affect SCE&G’s transmission system, see Electric Operations within the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCE&G is subject to regulation by the NRC with respect to the ownership, construction, operation and decommissioning of its currently operating and planned nuclear generating facilities. The NRC’s jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants.
RATE MATTERS
For a discussion of the impact of various rate matters, see the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G, and Note 2 to the consolidated financial statements for SCANA and SCE&G.
SCE&G’s gas rate schedules for its residential, small commercial and small industrial customers include a Weather Normalization Adjustment (WNA) approved by the SCPSC which is in effect for bills rendered for billing cycles in November through April. The WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues, but reduces fluctuations in revenues and earnings caused by abnormal weather.
PSNC Energy is authorized by the NCUC to utilize a CUT, a rate decoupling mechanism that breaks the link between revenues and the amount of natural gas sold. The CUT allows PSNC Energy to periodically adjust its base rates for residential and commercial customers based on average per customer consumption whether impacted by weather or other factors.
In January 2010, SCE&G filed an application with SCPSC requesting a 9.52% overall increase to retail electric base rates. If approved, the increase in rates would be phased in over three periods in July 2010, January 2011 and July 2011. A public hearing on this matter is scheduled to begin on May 24, 2010.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.
Fuel Cost Recovery Procedures
In June 2009, SCE&G filed a request with the SCPSC for approval of certain demand reduction and energy efficiency programs (DSM programs). SCE&G has requested the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM programs along with an incentive for investing in such programs. The SCPSC has scheduled a hearing on SCE&G’s request for April 1, 2010.
The SCPSC’s fuel cost recovery procedure determines the fuel component in SCE&G’s retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any over-collection or under-collection from the preceding 12-month period. The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, mercury and particulates. SCE&G may request a formal proceeding at any time should circumstances dictate such a review. In April 2009, the SCPSC approved a settlement agreement between SCE&G and the South Carolina Office of Regulatory Staff (ORS) and others, whereby SCE&G increased the fuel cost portion of its electric rates effective with the first billing cycle of May 2009. As part of the settlement, SCE&G agreed to spread the recovery of then under- collected fuel costs over a three-year period ending April 2012. SCE&G is allowed to collect interest on the deferred balance.
SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas cost incurred, including costs related to hedging natural gas purchasing activities. SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a twelve-month rolling average.
PSNC Energy is subject to a Rider D rate mechanism which allows it to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales. The Rider D rate mechanism also allows PSNC Energy to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost.
PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes, and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually.
ENVIRONMENTAL MATTERS
Federal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be predicted. For a more complete discussion of how these regulations and standards impact SCANA and SCE&G, see the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 11B to the consolidated financial statements for SCANA and SCE&G.
OTHER MATTERS
For a discussion of SCE&G’s insurance coverage for Summer Station, see Note 11A to the consolidated financial statements for SCANA and SCE&G.
ITEM 1A.
ITEM 1A. RISK FACTORS
The risk factors that follow relate in each case to SCANA Corporation (SCANA) and its subsidiaries (together, the Company), and where indicated the risk factors also relate to South Carolina Electric & Gas Company and its consolidated affiliates (SCE&G).
Commodity price changes, delays and other factors may affect the operating cost, capital expenditures and competitive positions of the Company's and SCE&G's energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.
Our energy businesses are sensitive to changes in coal, gas, oil and other commodity prices and availability. Any such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. SCE&G is able to recover the cost of fuel (including transportation) used in electric generation through retail customers' bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources. In the case of regulated natural gas operations, costs for purchased gas and pipeline capacity are recovered through retail customers' bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in gas costs may also result in lower usage by customers unable to switch to alternate fuels. Increases in fuel costs may also result in lower usage of electricity by customers. Furthermore, certain construction commodities such as copper and aluminum, which are used in our transmission and distribution lines and our electrical equipment, steel and concrete have experienced significant price volatility due to changes in worldwide demand. Also, to operate our air pollution control equipment, we use significant quantities of ammonia, limestone and lime. With mandated compliance deadlines for air pollution controls, demand for these reagents may increase and result in higher purchase costs.
The costs of large capital projects, such as the Company’s and SCE&G’s construction for environmental compliance and its construction of two new nuclear units, are significant and are subject to a number of risks and uncertainties that may adversely affect the cost, timing and satisfactory completion of the projects.
The Company's and SCE&G's business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects, such as projects for environmental compliance. For example, SCE&G and the South Carolina Public Service Authority (Santee Cooper) have agreed to jointly own, design, construct and operate two new 1,117-megawatt nuclear units at SCE&G's V.C. Summer Nuclear Station (the New Units), pursuant to which they are expending substantial resources for the evaluation, development and permitting of the project, site preparation and long lead-time procurement; substantial additional resources will be required for the construction and continued operation of the plant upon receipt of requisite approvals. Achieving the intended benefits of a large capital project of this type is subject to a number of uncertainties. For instance, the completion of projects within established budgets and timeframes is contingent upon many variables, including the obtaining of permits and licenses in a timely manner, our timely securing of labor and materials at estimated costs, our ability to finance such projects and weather. These projects also could be adversely affected by contractor or supplier non-performance, unforeseen engineering problems or changes in project design or scope. Our ability to maintain our operations or to complete construction projects (including new baseload generation) at reasonable cost, if at all, could be adversely affected by the availability of key parts or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, increased environmental pressures, a failure in the supply chain (whether resulting from the foregoing or other factors), and disruptions in the transportation of fuels. Furthermore, joint venture projects, such as the current construction of the New Units, are subject to the risk that the joint venture partner is either unable or unwilling to continue to fund its financial commitments to the projects. To the extent that delays occur, costs are not recoverable, or we are unable to otherwise effectively manage our capital projects, our results of operations, cash flows and financial condition may be adversely affected.
The use of derivative instruments could result in financial losses and liquidity constraints. The Company and SCE&G do not fully hedge against price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.
The Company and SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. In the future, we could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and interest rate contracts or if a counterparty fails to perform under a contract.
The Company and SCE&G attempt to manage commodity price exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be diminished.
Changing and complex laws and regulations to which the Company and SCE&G are subject could adversely affect revenues or increase costs or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.
The Company and SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the United States Federal Energy Regulatory Commission (FERC), the United States Nuclear Regulatory Commission (NRC), the United States Securities and Exchange Commission (SEC), the Internal Revenue Service, the United States Environmental Protection Agency (EPA), and a number of others. In addition, the Company and SCE&G are subject to regulation by agencies of the state governments of South Carolina, North Carolina and Georgia, including regulatory commissions, state environmental commissions, state employment commissions, and a number of others. Accordingly, the Company and SCE&G must comply with extensive federal, state and local laws and regulations. Such regulation widely affects the operation of our business. The effects encompass, among many other aspects of our business, the licensing and siting of facilities, safety, reliability of our transmission system, physical and cyber security of key assets, customer conservation through demand-side management programs, information privacy, the issuance of securities and borrowing of money, financial reporting, interaction among affiliates, the payment of dividends and employment practices. Changes to these regulations are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or SCE&G’s business.
The Company and SCE&G are subject to extensive rate regulation which could adversely affect operations. In particular, SCE&G's electric operations in South Carolina and the Company's gas distribution operations in South Carolina (comprised of SCE&G) and North Carolina are regulated by state utilities commissions. The Company’s interstate gas pipeline and SCE&G’s electric transmission system and nuclear operations are subject to extensive regulation and oversight from federal agencies, including the FERC and NRC. Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve. Although we believe we have constructive relationships with our regulators, our ability to obtain rate increases that will allow us to maintain reasonable rates of return is dependent upon regulatory discretion, and there can be no assurance that we will be able to implement rate increases when sought.
The Company and SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, that can increase our costs of operations and which may impact our business plans, or expose us to environmental liabilities.
The Company and SCE&G are presently subject to extensive federal, state and local environmental laws and regulations, including those relating to air emissions (such as reducing nitrogen oxide, sulfur dioxide, mercury emissions and particulate matter). There is a growing consensus that some form of regulation will be forthcoming at the federal, and possibly state, levels to impose limitations on greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units. A number of bills have been introduced in Congress that would require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted. In addition, the EPA is drafting a rule regarding the handling of coal ash and other combustion waste produced by power plants and a new mercury control rule to replace the prior Clean Air Mercury Rule. The EPA is expected to implement MACT (maximum achievable control technology) standards for mercury and other pollutants. Furthermore, the EPA has announced that it expects to overhaul rules governing effluent limitation standards for coal-fired power plants.
Compliance with these laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at our facilities. These expenditures have been significant in the past and are expected to increase in the future. Changes in compliance requirements or a more burdensome interpretation by governmental authorities of existing requirements may impose additional costs on us (such as additional taxes or emission allowances) or require us to incur additional capital expenditures or curtail some of our activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated portfolio renewable standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could harm our industry, our business and our results of operations and financial position, especially if emission or discharge limits are reduced, more extensive permitting requirements are imposed or additional regulatory requirements are imposed.
Furthermore, the Company and SCE&G are subject to the possibility that electric generation portfolio standards may be enacted at the federal or state level. Such standards could direct us to build or otherwise acquire generating capacity derived from alternative energy sources (generally, renewable energy such as biomass, solar, wind and tidal, and excluding fossil fuels, nuclear or hydro facilities). Such alternative energy may not be readily available in our service territories, and could be extremely costly to build or acquire, if at all, and to operate. Resulting increases in the price of electricity to recover the cost of these types of generation, if approved by regulatory commissions, could result in lower usage of electricity by our customers. Although we cannot predict whether such standards will be adopted or their specifics if adopted, compliance with such potential portfolio standards could significantly impact our industry, our capital expenditures, and our results of operations and financial position.
The Company and SCE&G are vulnerable to interest rate increases which would increase our borrowing costs, and may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.
The Company and SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company's and SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining investment grade debt ratings and the existence of a market for our commercial paper generally.
In mid-September 2008, a very severe dislocation of the commercial paper, long-term debt and equity markets occurred as concerns over bank solvency adversely affected the credit markets. As a result, access to these capital markets was very limited. Further, the amount of our outstanding commercial paper was significantly reduced, and the interest rates on such outstanding commercial paper significantly increased. Although the operation of these markets has returned to normal, the Company and SCE&G cannot predict whether similar dislocations will occur in the future or their duration.
The Company's and SCE&G's ability to draw on our respective bank revolving credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments and our ability to timely renew such facilities. Those banks may not be able to meet their funding commitments to the Company or SCE&G if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time. Longer term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses. Any disruption could require the Company and SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and SCE&G.
Disruptions in the capital markets and its actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA's pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact SCANA's results of operations, cash flows and financial position, including its shareholders' equity.
SCANA may not be able to maintain its leverage ratio at a level considered appropriate by debt rating agencies. This could result in downgrades of SCANA's and SCE&G’s debt ratings, thereby increasing their borrowing costs and adversely affecting their results of operations, cash flows and financial condition.
SCANA's leverage ratio of debt to capital was approximately 59% at December 31, 2009. SCANA has publicly announced its desire to reduce its present leverage ratio to levels between 54% and 57%, but SCANA's ability to do so depends on a number of factors. In the future, if SCANA is not able to reduce its leverage ratio, and maintain it within the desired range, SCANA's and SCE&G’s debt ratings may be affected, they may be required to pay higher interest rates on their long- and short-term indebtedness, and their access to the capital markets may be limited.
A downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect their ability to access capital and to operate their businesses, thereby adversely affecting results of operations, cash flows and financial condition.
Standard & Poor's Ratings Services (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) rate SCANA's long-term senior unsecured debt at BBB, Baa2 and BBB+, respectively. These ratings agencies rate SCANA’s junior subordinated debt (Hybrid) securities at BBB-, Baa3 and BBB-, respectively. S&P, Moody's and Fitch rate SCE&G's long-term senior secured debt at A-, A3 and A, respectively. S&P, Moody’s and Fitch rate the long-term senior unsecured debt of Public Service Company of North Carolina, Incorporated (PSNC Energy) at BBB+, A3 and A-, respectively. Moody’s carries a negative outlook on each of its ratings. S&P and Fitch carry a stable outlook on each of their ratings. If S&P, Moody's or Fitch were to downgrade any of these long-term ratings, particularly to below investment grade, borrowing costs would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease. Should the ratings on the hybrid securities at SCANA decline below investment grade, SCANA will be required to redeem such securities [IS THIS TRUE?]or take other prescribed remedial actions. S&P, Moody's and Fitch rate the short-term debt of SCE&G and PSNC Energy at A-2, P-2 and, respectively. If these short-term ratings were to decline, it could significantly limit access to sources of liquidity.
Operating results may be adversely affected by abnormal weather.
The Company and SCE&G have historically sold less power, delivered less gas and received lower prices for natural gas in deregulated markets, and consequently earned less income, when weather conditions have been milder than normal. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and SCE&G. In addition, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.
Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.
The utility industry has been undergoing dramatic structural change for several years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales has been introduced on a national level. Some states have also mandated or encouraged competition at the retail level. Increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, SCANA's and SCE&G's generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets would be required.
The Company and SCE&G are subject to risks associated with changes in business and economic climate which could adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.
Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Some economic sectors important to our customer base may be particularly affected. Adverse events, economic or otherwise, may also affect the operations of key customers. Such events may result in the loss of customers, changes in customer usage patterns and in the failure of customers to make timely payments to us. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally or legislative or regulatory actions.
In addition, conservation efforts and/or technological advances may cause or enable customers to significantly reduce their usage of the Company’s and SCE&G’s products and adversely affect sales, sales growth, and customer usage patterns.
Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed.
Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.
Critical processes or systems in the Company’s or SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission line failure, information systems failure or security breach, the effects of drought (including reduced water levels) on the operation of emission control or other generation equipment, and the effects of a pandemic or terrorist attack on our workforce or facilities or on the ability of vendors and suppliers to maintain services key to our operations.
In particular, as the operator of power generation facilities, SCE&G could incur problems such as the breakdown or failure of power generation or emission control equipment, transmission lines, other equipment or processes which would result in performance below assumed levels of output or efficiency. In addition, any such breakdown or failure may result in SCE&G purchasing emissions credits or replacement power at market rates, if such replacement power is available at all. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. These purchases are subject to state regulatory prudency reviews for recovery through rates.
Covenants in certain financial instruments may limit SCANA's ability to pay dividends, thereby adversely impacting the valuation of our common stock and our access to capital.
Our assets consist primarily of investments in subsidiaries. Dividends on our common stock depend on the earnings, financial condition and capital requirements of our subsidiaries, principally SCE&G, PSNC Energy and SCANA Energy Marketing, Inc. (SEMI). Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.
A significant portion of SCE&G's generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition. These risks will increase as the New Units are developed
In 2009, the V.C. Summer Nuclear Station, operated by SCE&G, provided approximately 4.6 million MWh, or 18 % of our generation capacity, both of which figures are expected to increase if the New Units are completed. As such, SCE&G is subject to various risks of nuclear generation, which include the following:
·
The potential harmful effects on the environment and human health resulting from a release of radioactive
materials in connection with the operation of nuclear facilities and the storage, handling and disposal of
radioactive materials;
·
Limitations on the amounts and types of insurance commercially available to cover losses that might arise
in connection with our nuclear operations or those of others in the United States;
·
Uncertainties with respect to procurement of enriched uranium fuel and the storage of spent uranium fuel;
·
Uncertainties with respect to contingencies if insurance coverage is inadequate; and
·
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at
the end of their operating lives.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident, if a major incident should occur at a domestic nuclear facility, it could harm our results of operations, cash flows and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Finally, in today's environment, there is a heightened risk of terrorist attack on the nation's nuclear facilities, which has resulted in increased security costs at our nuclear plant.
Failure to retain and attract key personnel could adversely affect the Company’s and SCE&G’s operations and financial performance.
Implementation of our strategic plan and growth strategy requires that we attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate and grow our business. Competition for these employees is high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance.
The Company and SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial position, and access to capital.
From time to time, the Company and SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plant and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved by regulators), to the detriment of the Company or SCE&G. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial position, as well as limit our ability to access capital.
The Company and SCE&G are subject to the reputational risks that may result from a failure of their adherence to high standards of compliance with laws and regulations, ethical conduct, operational effectiveness, and safety of employees, customers and the public. These risks could adversely affect the valuation of our common stock and the Company’s and SCE&G’s access to capital.
The Company and SCE&G are committed to comply with all laws and regulations, to focus on the safety of employees, customers and the public and to maintain the privacy of information related to our customers and employees. The Company and SCE&G also are committed to operational excellence and, through their Code of Conduct and Ethics, to maintain high standards of ethical conduct in their business operations. A failure to meet these commitments may subject the Company and SCE&G not only to fraud, litigation and financial loss, but also to reputational risk that could adversely affect the valuation of SCANA’s stock, adversely affect the Company’s and SCE&G’s access to capital, and result in further regulatory oversight.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not Applicable
ITEM 2.
ITEM 2. PROPERTIES
SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds, directly or indirectly, all of the capital stock of each of its subsidiaries.
SCE&G’s bond indenture, securing the First Mortgage Bonds issued thereunder, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO’s Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.
For a brief description of the properties of SCANA’s other subsidiaries, which are not significant as defined in Rule 1-02 of Regulation S-X, see Item 1. BUSINESS-SEGMENTS OF BUSINESS-Nonregulated Businesses.
The following map indicates significant electric generation properties, which are further described below. Natural gas transmission and distribution properties, though not depicted on the map, are also described below.
ELECTRIC PROPERTIES
SCE&G owns each of the electric generating facilities listed below unless otherwise noted.
Facility
Present
Fuel Capability
Location
Year
In-Service
Net Generating
Capacity
(Summer Rating) (MW)
Steam Turbines:
Summer(1)
Nuclear
Parr, SC
McMeekin
Coal/Gas
Irmo, SC
Canadys
Coal/Gas
Canadys, SC
Wateree
Coal
Eastover, SC
Williams(2)
Coal
Goose Creek, SC
Cope
Coal
Cope, SC
COGEN South(3)
Biomass/Coal
Charleston, SC
Combined Cycle:
Urquhart(4)
Coal/Gas/Oil
Beech Island, SC
1953/2002
Jasper
Gas/Oil
Hardeeville, SC
Hydro(5):
Saluda
Irmo, SC
Fairfield Pumped Storage
Parr, SC
(1) Represents SCE&G’s two-thirds portion of the Summer Station (one-third owned by Santee Cooper).
(2) The coal-fired steam unit at Williams Station is owned by GENCO.
(3) SCE&G receives shaft horsepower from COGEN South, LLC, a biomass/coal cogeneration facility, to operate
SCE&G’s generator.
(4) Two combined-cycle turbines burn natural gas or fuel oil to produce 330 MW of electric generation and use exhaust
heat to power two 65 MW turbines at the Urquhart Generating Station. Unit 3 is a 95 MW coal-fired steam unit.
(5) SCE&G also owns three other hydro units in South Carolina that were placed in service in 1905 and 1914 and have
an aggregate net generating capacity of 21 MW.
SCE&G owns 16 combustion turbine peaking units fueled by gas and/or oil located at various sites in SCE&G’s service territory. These turbines were placed in service at various times from 1961 to 2009 and have aggregate net generating capacity of 348 MW.
SCE&G owns 435 substations having an aggregate transformer capacity of 28 million KVA (kilovolt-ampere). The transmission system consists of 3,274 miles of lines, and the distribution system consists of 18,187 pole miles of overhead lines and 6,552 trench miles of underground lines.
NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES
SCE&G’s natural gas system consists of 15,922 miles of distribution mains and related service facilities. SCE&G also owns two LNG plants, one located near Charleston, South Carolina and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF of natural gas. The Salley facility can store the liquefied equivalent of 900 MMCF of natural gas and has no liquefying capabilities. The LNG facilities have the capacity to regasify approximately 60 MMCF per day at Charleston and 90 MMCF per day at Salley.
CGT’s natural gas system consists of 1,468 miles of transmission pipeline of up to 24 inches in diameter. CGT’s system transports gas to its customers from the transmission systems of Southern Natural and Transco and from Port Wentworth and Elba Island, Georgia.
PSNC Energy’s natural gas system consists of 614 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy’s distribution system consists of 9,928 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly-owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC Energy owns, through a wholly-owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2009, are described below. These issues affect SCANA and, to the extent indicated, also affect SCE&G.
Environmental Matters
SCE&G has been named, along with 53 others, by the United States Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List in April 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2010. The site has not been remediated, nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.
SCE&G is responsible for four manufactured gas plants (MGP) sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation or monitoring under work plans approved by South Carolina Department of Health and Environmental Control (DHEC). SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $7.7 million. In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates. At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $4.4 million, the estimated remaining liability at December 31, 2009. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.
Litigation
In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette, and Mark Rudd and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims. SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to easement grantors situated in Charleston County, South Carolina. In February 2008 the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County. In July 2008, the plaintiff’s motion to add SCI to the lawsuit as an additional defendant was granted. Trial is not anticipated before the summer of 2010. SCE&G and SCI will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.
SCANA and SCE&G are also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material adverse impact on their respective results of operations, cash flows or financial condition.
ITEM 4.
ITEM 4. RESERVED
EXECUTIVE OFFICERS OF SCANA CORPORATION
The executive officers are elected at the annual meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such annual meeting, unless (1) a resignation is submitted, (2) the Board of Directors shall otherwise determine or (3) as provided in the By-laws of SCANA. Positions held are for SCANA and all subsidiaries unless otherwise indicated.
Name
Age
Positions Held During Past Five Years
Dates
William B. Timmerman
Chairman of the Board, President and Chief Executive Officer
*-present
Jimmy E. Addison
Senior Vice President and Chief Financial Officer
Vice President-Finance
2006-present
*-2006
George J. Bullwinkel
President and Chief Operating Officer-SEMI, SCI and ServiceCare
*-present
Sarena D. Burch
Senior Vice President-Fuel Procurement and Asset Management-SCE&G
and PSNC Energy
Senior Vice President-Fuel Procurement and Asset Management-South Carolina Pipeline Corporation, predecessor to CGT
*-present
*-2006
Stephen A. Byrne
Executive Vice President-Generation, Nuclear and Fossil Hydro-SCE&G
Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G
2009-present
*-2009
Paul V. Fant
President and Chief Operating Officer-CGT
Senior Vice President - SCANA
Senior Vice President - Transmission Services - SCE&G
*-present
2008-present
*-2007
Ronald T. Lindsay
Senior Vice President, General Counsel and Assistant Secretary
Executive Vice President, General Counsel and Secretary of Bowater Incorporated, Greenville, South Carolina
Senior Vice President, General Counsel and Secretary of
Bowater Incorporated
2009-present
2006-2008
*-2006
Kevin B. Marsh
President and Chief Operating Officer - SCE&G
Senior Vice President and Chief Financial Officer
2006-present
*-2006
Charles B. McFadden
Senior Vice President-Governmental Affairs and Economic Development-
SCANA Services
*-present
* Indicates position held at least since March 1, 2005.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,
AND ISSUER PURCHASES OF EQUITY SECURITIES
COMMON STOCK INFORMATION
SCANA Corporation:
Price Range (New York Stock Exchange Composite Listing):
SCANA common stock trades on The New York Stock Exchange, using the ticker symbol SCG. Newspaper stock listings use the name SCANA. At February 20, 2010 there were 123,878,780 shares of SCANA Common Stock outstanding which were held by approximately 31,112 shareholders of record. For a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2009, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
SCANA declared quarterly dividends on its common stock of $.47 per share in 2009 and $.46 per share in 2008. On February 11, 2010, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.475 per share, an increase of 1.1%. The new dividend is payable April 1, 2010 to shareholders of record on March 10, 2010. For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources - Financing Limits and Related Matters and Note 6 to the consolidated financial statements for SCANA.
SCE&G:
All of SCE&G’s common stock is owned by SCANA and is not traded. During 2009 and 2008 SCE&G paid $167.8 million and $153.8 million, respectively, in cash dividends to SCANA. For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources - Financing Limits and Related Matters and Note 6 to the consolidated financial statements for SCE&G.
SECURITIES RATINGS (As of February 20, 2010)
For additional information regarding these securities, see Notes 4, and 5 to the consolidated financial statements for SCANA and SCE&G.
Securities ratings used by Moody’s, S&P and Fitch are as follows:
(1) Additional Modifiers: 1, 2, 3 (Aa to Baa) (2) Additional Modifiers: +, - (AA to BBB)
A security rating should be evaluated independently of other ratings and is not a recommendation to buy, sell or hold securities. The assigning rating organization may revise or withdraw its security ratings at any time.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(1) In 2006, includes a reduction of an accrual upon settlement of certain litigation associated with SCANA’s prior sale of its
propane assets of $4.7 million.
(2) Reflects the 2006 adoption of revised accounting guidance related to share-based payments, recorded as the
cumulative effect of an accounting change of $6 million for SCANA and $4 million for SCE&G.
(3) Reflects the change in business model of CGT from an intrastate supplier of natural gas to a transportation-only,
interstate pipeline company in November 2006.
SCANA CORPORATION
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
South Carolina Electric & Gas Company (SCE&G, together with its consolidated affiliates, the Company) is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas. SCE&G’s business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers more than 25,000 square miles.
Key Earnings Drivers and Outlook
During 2009, the southeast continued to suffer under the effects of the recession. At December 31, 2009 the preliminary estimate of seasonally adjusted unemployment for South Carolina was 12.6%, a rate significantly higher than the rate at December 31, 2008. Customer growth remained positive, but sluggish, throughout 2009. In addition, SCE&G continued to experience declines in customer usage. The Company expects that any economic recovery will be slow in 2010, and cannot determine when or if customer growth and usage trends may return to pre-2008 levels.
Over the next five years, key earnings drivers for SCE&G will be additions to utility rate base, consisting primarily of capital expenditures for environmental facilities, new generating capacity and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage and the level of growth of operation and maintenance expenses and taxes.
Electric Operations
The electric operations segment is comprised of the electric operations of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 2009 SCE&G provided electricity to approximately 655,000 customers in an area covering nearly 17,000 square miles. GENCO owns a coal-fired generating station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowance requirements. Both GENCO and Fuel Company are consolidated with SCE&G for financial reporting purposes.
Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity is 11.0%. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.
In 2008, SCE&G contracted with Westinghouse Electric Company LLC and Stone & Webster, Inc. for the design and construction of two 1,117-megawatt nuclear electric generating units at the site of V. C. Summer Nuclear Station (Summer Station). SCE&G and South Carolina Public Service Authority (Santee Cooper) will be joint owners and share operating costs and generation output of the units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. The successful completion of the project would result in an increase of the Company’s utility plant in service of approximately 68% over its 2009 level. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.
In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011 or early 2012. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.
The Company expects that significant legislative or regulatory initiatives regarding energy will be undertaken, particularly at the federal level. These initiatives may require the Company to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under a renewable portfolio standard or “RPS”). New legislation or regulations may also impose stringent requirements on existing power plants to reduce emissions of sulfur dioxide, nitrogen oxides and mercury. It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. The Company cannot predict whether such legislation or regulations will be enacted, and if they are, the conditions they would impose on utilities.
The United States Environmental Protection Agency (EPA) has publicly stated its intention to propose new federal regulations affecting the management and disposal of coal combustion products (CCP), such as ash, in 2010. Such regulations could result in the treatment of some CCPs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.
Gas Distribution
The gas distribution segment is comprised of the local distribution operations of SCE&G and is primarily engaged in the purchase and sale of natural gas to retail customers in portions of South Carolina. At December 31, 2009 this segment provided natural gas to approximately 310,000 customers.
Operating results for gas distribution are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity of 10.25%.
Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact SCE&G’s ability to retain large commercial and industrial customers. Significant supply disruptions did occur in September and October 2005 as a result of hurricane activity in the Gulf of Mexico, resulting in the curtailment during the period of most large commercial and industrial customers with interruptible supply agreements. While significant supply disruptions have not been experienced since 2005, the price of natural gas remains volatile. Due to the recession, the demand for natural gas has decreased overall, resulting in significantly lower prices for this commodity in 2009. The long-term impact of volatile gas prices and gas supply has not been determined.
RESULTS OF OPERATIONS
Net Income
Net income was as follows:
•
2009 vs 2008
Net income increased $12.9 million due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in favor of the Company, by higher gas margin of $3.0 million, by decreased incentive compensation of $3.1 million and by decreased generation, transmission and distribution expenses of $4.6 million. These increases to net income were partially offset by lower electric margin (excluding the impact of adjustments related to the adoption of new electric depreciation rates, the effects of which were offset by a reduction of revenue under regulatory direction-see Electric Operations and Other Operating Expenses) of $14 million. All amounts are net of tax.
•
2008 vs 2007
Net income increased primarily due to higher electric margin of $49.0 million and higher gas margin of $4.1 million. These increases were partially offset by increased generation, transmission and distribution expenses of $1.6 million, by increased incentive compensation and other benefits of $4.5 million, by increased depreciation expense of $6.9 million, by $2.5 million due to higher customer service expense, including bad debt expense and by $1.2 million due to lower pension income. All amounts are net of tax.
Pension Cost (Income)
Pension cost (income) was recorded on SCE&G’s financial statements as follows:
The Company recorded significant pension income in each of 2008 and 2007. Due to the significant decline in plan asset values during the fourth quarter of 2008 stemming from turmoil in the financial markets, the Company recorded significant pension cost in 2009. However, no contribution to the pension trust was necessary in or for 2009, nor did limitations on benefit payments apply.
Additionally, in February 2009, SCE&G was granted accounting orders by the SCPSC which allow it to mitigate a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above the level of pension income which is included in current rates for its retail electric and gas distribution regulated operations. These costs are being deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively. See further information at Liquidity and Capital Resources and Critical Accounting Policies and Estimates.
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 11.5% of income before income taxes in 2009, 6.3% in 2008 and 3.8% in 2007.
Dividends Declared
SCE&G’s Board of Directors declared the following dividends on common stock held by SCANA during 2009:
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margins were as follows:
•
2009 vs 2008
Margin decreased by $6.6 million due to lower residential and commercial usage (including the partially offsetting effects of favorable weather), by $11.9 million due to lower industrial sales, by lower off-system sales of $15.9 million. Margins also decreased by $13.6 million due to the adoption of new, lower SCPSC-approved electric depreciation rates, the effect of which was offset within operating revenues. The decreases were partially offset by higher residential and commercial customer growth of $6.2 million and by increases in base rates by the SCPSC under the BLRA of $10.8 million which became effective for bills rendered on or after March 29, 2009.
•
2008 vs 2007
Margin increased by $74.5 million due to increased retail electric rates that went into effect in January 2008 and $16.6 million due to residential and commercial customer growth. These increases were offset by $5.4 million due to lower off-system sales, by $3.5 million due to lower industrial sales and $10.0 million in lower residential and commercial usage.
Megawatt hour (MWh) sales volumes, by class, related to the electric margin above were as follows:
•
2009 vs 2008
Territorial sales volumes decreased by 95 MWh due to decreased average use, partially offset by favorable weather, and by 828 MWh due to lower industrial sales volumes as a result of a recessionary economy, partially offset by an increase of 76 MWh due to residential and commercial customer growth. NMST volumes decreased due to lower regional demand.
•
2008 vs 2007
Territorial sales volumes decreased by 252 MWh due to weather and by 115 MWh due to lower industrial sales volumes as a result of a recessionary economy, partially offset by an increase of 238 MWh due to residential and commercial customer growth.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins (including transactions with affiliates) were as follows:
•
2009 vs 2008
Margin increased by $2.7 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2008, by $3.7 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009, offset by a decrease of $3.0 million due to decreased customer usage.
•
2008 vs 2007
Margin increased by $3.6 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2007, by $1.1 million due to SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2008, and by $2.4 million due to other customer growth.
Dekatherm (DT) sales volumes by class, including transportation gas, were as follows:
•
2009 vs 2008
Residential sales volume increased primarily due to customer growth and weather. Commercial and industrial sales volume decreased primarily as a result of weak economic conditions.
•
2008 vs 2007
Residential, commercial and transportation gas sales volume increased primarily due to customer growth. Industrial gas sales volume decreased primarily due to a loss of customers as a result of a recessionary economy.
Other Operating Expenses
Other operating expenses, which arose from the operating segments previously discussed, were as follows:
•
2009 vs 2008
Other operation and maintenance expenses decreased by $7.4 million due to lower generation, transmission and distribution expenses and by $5.0 million due to lower incentive compensation and other benefits. Depreciation and amortization expense decreased $13.6 million due to the implementation of new, lower SCPSC-approved electric depreciation rates in 2009, offset by higher depreciation expense of $9.5 million due to 2009 net property additions. Other taxes increased primarily due to higher property taxes.
•
2008 vs 2007
Other operation and maintenance expenses increased by $2.6 million due to higher generation, transmission and distribution expenses, by $7.3 million due to higher incentive compensation and other benefits, by $4.1 million due to higher customer service expense, including bad debt expense and by $1.9 million due to lower pension income. Depreciation and amortization expense decreased by $4.6 million due to the 2007 expiration of the synthetic fuel tax credit program (see Income Taxes - Recognition of Synthetic Fuel Tax Credits) and $8.5 million due to the 2007 expiration of a three-year amortization of previously deferred purchased power costs. These decreases were offset by higher depreciation expense of $10.3 million due to 2008 net property additions. Other taxes increased primarily due to higher property taxes.
Other Income (Expense)
Other income (expense) includes the results of certain non-utility activities. Components of other income (expense), were as follows:
•
2009 vs 2008
Total other income (expense) decreased $10.9 million due to decreased pension income and by $6.9 million in gains on sale of assets in 2008. These decreases were partially offset by an increase of $14.3 million in interest income. (See Economic Impact Zone (EIZ) discussion under “Resolution of EIZ Tax Credit Uncertainty” below.)
•
2008 vs 2007
Other income increased by $1.9 million due to increased coal sales to non-affiliates. Other expenses increased $1.7 million due to increased coal inventory expenses related to the increased coal sales to non-affiliates.
Resolution of EIZ Tax Credit Uncertainty
SCE&G earned an Economic Impact Zone state income tax credit (EIZ credit) in 1996 based on qualifying property additions. This EIZ credit exceeded its state tax liability for the 1996 tax year, leaving $15.3 million unused. The Company’s attempt to carry forward the unused credit to tax years 1997 and 1998 was contested by the South Carolina Department of Revenue. In September 2009, the South Carolina Supreme Court decided the matter in the Company’s favor. As a result of the favorable resolution of this uncertainty, the Company recorded the refund for the previously contested EIZ credit of $15.3 million and an additional $14.3 million of interest income.
Prior to this favorable Supreme Court decision, and pursuant to accounting guidance concerning income tax uncertainties, the value of the contested credit had not been reflected in the Company’s statement of income. SCE&G’s practice has been to amortize EIZ credits to income over the lives of the properties that gave rise to the credits. Accordingly, upon resolution of this prior uncertainty, the Company recorded a cumulative adjustment in the third quarter 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes. The remainder of these EIZ credits will be amortized to income over the remaining life of the related properties that gave rise to the tax benefit, as a reduction in income taxes. The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.
Interest Expense
Components of interest expense, excluding the debt component of AFC, were as follows:
Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year. Other interest expense decreased in each year primarily due to lower principal balances on short-term debt over the prior year.
Income Taxes
Income tax expense decreased in 2009 primarily due to the recognition of a tax benefit from the resolution of the EIZ tax credit uncertainty in favor of the Company (see discussion above at Other Income (Expense)) and due to changes in operating income. Income taxes increased in 2008 primarily due to the recognition at SCE&G of $17.4 million in synthetic fuel tax credits in 2007 (see discussion under “Recognition of Synthetic Fuel Tax Credit” below) and due to changes in operating income.
Recognition of Synthetic Fuel Tax Credits
SCE&G held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel, the use of which fuel qualified for federal income tax credits. Under an accounting methodology approved by the SCPSC, construction costs related to the Lake Murray back-up dam project were recorded in utility plant in service in a special dam remediation account, outside of rate base, and accelerated depreciation was recognized against the balance in this account, subject to the availability of the synthetic fuel tax credits. The synthetic fuel tax credit program expired at the end of 2007.
For 2007, the level of depreciation expense and related tax benefit recognized in the income statement was equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account declined as accelerated depreciation was recorded. Although these entries collectively had no impact on consolidated net income, they did impact individual line items within the 2007 income statement, as follows:
Available credits were not sufficient to fully recover the construction costs of dam remediation; therefore, recovery of remaining costs is being sought in connection with a retail electric rate application filed with the SCPSC in January 2010. In addition, SCE&G records non-cash carrying costs on the unrecovered investment, which amounts were $5.4 million in 2009, $5.5 million in 2008 and $5.6 million in 2007. As of December 31, 2009, remaining unrecovered costs were $75.5 million. The Company expects these costs to be recoverable through rates.
LIQUIDITY AND CAPITAL RESOURCES
The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company’s ratio of earnings to fixed charges for the year ended December 31, 2009 was 3.25.
The Company’s cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of the Company to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. The Company’s future financial position and results of operations will be affected by SCE&G’s ability to obtain adequate and timely rate and other regulatory relief.
The Company’s issuance of various securities, including short- and long-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including the SCPSC and Federal Energy Regulatory Commission (FERC).
Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $751 million in 2009 and are estimated to be $1.0 billion in 2010.
The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2010-2012, which are subject to continuing review and adjustment, are as follows:
Estimated Capital Expenditures
The Company’s contractual cash obligations as of December 31, 2009 are summarized as follows:
Contractual Cash Obligations
Included in the table above in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station. SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional units, with SCE&G accounting for 55 percent of the cost and output and Santee Cooper the remaining 45 percent. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019. SCE&G’s estimated projected costs for the two additional units, in future dollars and excluding AFC, are summarized below. To the extent that actual contracts were put in place by December 31, 2009, obligations arising from these contracts are included in the purchase obligations within the Contractual Cash Obligations table above.
Also included in purchase obligations are customary purchase orders under which SCE&G has the option to utilize certain vendors without the obligation to do so. SCE&G may terminate such arrangements without penalty.
Included in other commercial commitments are estimated obligations for coal and nuclear fuel purchases. See Note 11F to the consolidated financial statements.
The Company also has a legal obligation associated with the decommissioning and dismantling of Summer Station and other conditional asset retirement obligations that are not listed in the contractual cash obligations above. See Notes 1B and 11G to the consolidated financial statements.
In addition to the contractual cash obligations above, SCANA sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no required contributions are anticipated until after 2011. The Company’s cash payments under the health care and life insurance benefit plan were $9.3 million in 2009, and such annual payments are expected to increase up to $11 million in the future.
The Company does not have any recorded or unrecorded tax-related contingencies.
The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term debt and capital contributions from its parent, SCANA. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and the foreseeable future.
Financing Limits and Related Matters
The Company’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including the SCPSC and FERC. Financing programs currently utilized by the Company are as follows.
SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $100 million of short-term indebtedness. The authority to make such issuances will expire on February 5, 2012.
At December 31, 2009, SCE&G (including Fuel Company) had available the following committed lines of credit (LOC) and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
(a) The Company's committed lines of credit serve to back-up the issuance of commercial paper or to provide liquidity
support. Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company
of LOC advances or short-term commercial paper.
The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wachovia Bank, National Association and Bank of America, N. A. each provide 14.3% of the aggregate $650 million credit facilities, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%. Four other banks provide the remaining 9.6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company). When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).
Challenging conditions during late 2008 and early 2009 tested the Company’s liquidity and its ability to access short-term funding sources. During this period, all of the banks in the Company’s revolving credit facilities fully funded draws requested of them. As of December 31, 2009, the Company had borrowed $100 million from its $650 million facilities, had approximately $254 million in commercial paper borrowings outstanding, was obligated under $0.3 million in LOC-supported letters of credit, and had approximately $134 million in cash and temporary investments. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.
At December 31, 2009, the Company had net available liquidity of approximately $430 million, and the Company’s revolving credit facilities are in place until December 2011. The Company’s overall debt portfolio has a weighted average maturity of over 17 years and bears an average cost of 4.34%. Most long-term debt, other than facility draws, effectively bears fixed interest rates or is swapped to fixed. To further preserve liquidity, the Company rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.
SCE&G’s Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock.
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2009, approximately $57 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.
SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its First Mortgage Bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2009, the Bond Ratio was 5.18.
Financing Activities
During 2009 the Company experienced net cash inflows related to financing activities of $332 million primarily due to the issuance of long-term debt, partially offset by repayment of short-term debt and payment of dividends.
In December 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock representing an aggregate par value of $113.4 million.
In December 2009, SCE&G issued $150 million of First Mortgage Bonds bearing an annual interest rate of 5.50% and maturing on December 15, 2039. Proceeds from the sale were used to finance capital expenditures, and for general corporate purposes.
In March 2009, SCE&G issued $175 million of First Mortgage Bonds bearing an annual interest rate of 6.05% and maturing on January 15, 2038. Proceeds from the sale were used to repay short-term debt and for general corporate purposes.
For additional information on significant financing transactions, see Note 4 to the consolidated financial statements.
ENVIRONMENTAL MATTERS
The Company’s regulated operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the Clean Air Act, as amended (CAA), the Clean Air Interstate Rule (CAIR), the Clean Water Act (CWA), the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), among others. Compliance with these environmental requirements involves significant capital and operating costs, which the Company expects to recover through existing ratemaking provisions.
For the three years ended December 31, 2009, the Company’s capital expenditures for environmental control totaled $585.0 million. These expenditures were in addition to environmental expenditures included in “Other operation and maintenance” expenses, which were $41.2 million during 2009, $43.7 million during 2008, and $34.0 million during 2007. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $13.1 million for 2010 and $48.4 million for the four-year period 2011-2014. These expenditures are included in the Company’s Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.
On June 26, 2009, the United States House of Representatives narrowly passed energy legislation that would mandate significant reductions in greenhouse gas (GHG) emissions and require electric utilities to generate an increasing percentage of their power from renewable sources. The bill would require, among other things, that GHG emissions be reduced to 17% below 2005 levels by 2020, and to 83% below 2005 levels by 2050. Companies could meet these standards either through emission reductions or by obtaining emission allowances (Cap and Trade). The bill also would impose a renewable energy standard (RES) on the total generation of electric utilities beginning at 6% in 2012 and increasing to 20% by 2020. New nuclear generation would be excluded from the RES total generation baseline calculation, and one quarter of the RES mandate could be met through energy efficiency measures. The United States Senate is also considering legislation that would address GHG emissions and would establish an
RES. The Company cannot predict if or when the legislation described above will become law or what requirements would be imposed on the Company by such legislation. The Company expects that any costs incurred to comply with such legislation would be recoverable through rates.
At the state level, no significant environmental legislation that would affect the Company’s operations advanced during 2009. The Company cannot predict whether such legislation will be introduced or enacted in 2010, or if new regulations or changes to existing regulations at the state or federal level will be implemented in the coming year.
Air Quality
With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, SCE&G and GENCO are subject to certain climate-related financial risks, including those involving regulatory requirements responsive to GHG emissions, as well as those involving physical impacts which could arise from global climate change. Certain other business and financial risks arising from such climate change could also arise. The Company cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact the Company, and the following discussion should not be considered all-inclusive.
From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G has announced plans to construct two new nuclear generating plants which are expected to significantly reduce GHG emission levels once they are completed and dispatched, potentially displacing some of the current coal-fired generation sources.
See also the discussion of the court action on the Clean Air Interstate Rule (CAIR) below. Even while the rule has been in flux, the Company has continued with its scrubber and selective catalytic reactor (SCR) construction projects with the expectation that new rules will be forthcoming.
In 2005, the EPA issued the CAIR which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements. SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction. SCE&G also is installing a wet limestone scrubber at Wateree Station. The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these scrubber projects, of which approximately $435 million has already been spent. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
Physical effects associated with climate changes could include the impact of possible changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to the Company’s electric system, as well as impacts on employees and customers and on the Company’s supply chain and many others. Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms. To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties and also collects funds from customers for its storm damage reserve (see Note 1 to the consolidated financial statements). As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams, and applicable personnel participate in ongoing training and related simulations in advance of such storms, all in order to allow the Company to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.
In December 2009 the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions by November 2011. On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as the Company’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions. The Company expects that any costs incurred to comply with greenhouse gas emission requirements will be recoverable through rates.
In 2005 the EPA issued the Clean Air Mercury Rule (CAMR) which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule, and on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. The Company expects the EPA to issue a new mercury emissions rule but cannot predict when such a rule will be issued or what requirements it will impose.
The EPA is conducting an enforcement initiative against the utilities industry related to the new source review provisions and the new source performance standards of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the United States Department of Justice (DOJ), on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.
To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether the Company will be affected by the initiative in the future. The Company believes that any enforcement action relative to its compliance with the CAA would be without merit. The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with New Source Review (NSR).
Water Quality
The Clean Water Act, as amended (CWA), provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all, and renewed for all, of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include limitations to mixing zones and toxicity-based standards. These provisions, if passed, could have a material adverse impact on the financial condition, results of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations would be recoverable through rates.
Hazardous and Solid Wastes
The EPA has publicly stated its intention to propose new federal regulations affecting the management and disposal of coal combustion products (CCP), such as ash, in 2010. Such regulations could result in the treatment of some CCPs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2009, the federal government has not accepted any spent fuel from Summer Station or any other nuclear generating facility, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station through dry cask storage or other technology as it becomes available.
The provisions of CERCLA authorize the EPA to require the clean up of hazardous waste sites. In addition, the state of South Carolina has a similar law. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates. The Company has assessed the following matters:
Electric Operations
SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List in April 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA, and funded a Feasibility Study that is expected to be completed in 2010. The site has not been remediated nor has a clean-up cost been estimated. Although a basis for the allocation of clean up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, is expected to be recoverable through rates.
Gas Distribution
SCE&G is responsible for four decommissioned manufactured gas plant (MGP) sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control (DHEC). SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $7.7 million. In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates. At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.
REGULATORY MATTERS
Material retail rate proceedings are described in more detail in Note 2 to the consolidated financial statements.
SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.
SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting.
The Natural Gas Rate Stabilization Act of 2005 allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.
Effective February 12, 2010 the Pipeline and Hazardous Materials Safety Administration issued a final rule establishing integrity management requirements for gas distribution pipeline systems, similar to those for transmission pipelines. The rule gives SCE&G until August 2, 2011 to develop and implement a program for compliance with the rule. SCE&G has not determined what impact the rule will have on its operations. SCE&G believes that any additional cost incurred to comply with the rule will be recoverable through rates.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Following are descriptions of the Company’s accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.
Utility Regulation
The Company’s regulated operations record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria of accounting for rate-regulated utilities, and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations, liquidity or financial position of the Company’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. See Note 1B to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.
The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2009, the Company’s net investments in fossil/hydro and nuclear generation assets were $2.8 billion and $1.0 billion, respectively.
Revenue Recognition and Unbilled Revenues
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2009 and 2008, accounts receivable included unbilled revenues of $104.3 million and $97.1 million, respectively, compared to total revenues of $2.6 billion and $2.8 billion for the years 2009 and 2008, respectively.
Nuclear Decommissioning
Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Among the factors that could change the Company’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and timing of cash flows. Changes in any of these estimates could significantly impact the Company’s financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).
SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station. The cost estimate assumes that the site would be maintained over a period of 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
Accounting for Pensions and Other Postretirement Benefits
SCANA recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. SCANA’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $40.0 million ($34.6 million attributable to SCE&G) recorded in 2009 reflects the use of a 6.45% discount rate, derived using a cash flow matching technique, and an assumed 8.50% long-term rate of return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 6.20% in 2009 would have increased SCANA’s aggregate pension income by $1.1 million. Had the assumed long-term rate of return on assets been 8.25%, SCANA’s pension cost for 2009 would have increased by $1.5 million.
As noted in Results of Operations above, due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, SCE&G recorded significant amounts of pension cost in 2009 compared to the pension income recorded in 2008 and previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allow it to mitigate a significant portion of this increased pension expense by deferring as a regulatory asset the amount of pension expense above the level of pension income which is included in current rates. These costs will be deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.
SCANA accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 6.45%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $13.0 million for 2009. Had the selected discount rate been 6.20%, the expense for 2009 would have been $0.1 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.
Asset Retirement Obligations
The Company accrues for the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation in accordance with applicable accounting guidance. The obligations are recognized at fair value in the period in which they are incurred and associated asset retirement costs are capitalized as a part of the carrying amount of the related long-lived assets. Because such obligations relate primarily to the Company’s regulated utility operations, their recording has no significant impact on results of operations. As of December 31, 2009, the Company has recorded an asset retirement obligation (ARO) of $111 million for nuclear plant decommissioning (as discussed above) and an ARO of $347 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded in accordance with the relevant accounting guidance are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company’s utilities remains in place.
OTHER MATTERS
Off-Balance Sheet Transactions
SCE&G does not hold significant investments in unconsolidated special purpose entities. SCE&G does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, equipment and rail cars.
Claims and Litigation
For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS and Note 11 to the consolidated financial statements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for purposes other than trading.
The tables below provide information about long-term debt issued by SCE&G which is sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
The above tables exclude long-term debt of $30 million at December 31, 2009 and $37 million at December 31, 2008, which amounts do not have stated interest rates associated with them.
Commodity Price Risk
The following table provides information about the Company’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value represents quoted market prices.
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.
SCE&G’s tariffs include a purchased gas adjustment (PGA) that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is deferred.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
South Carolina Electric & Gas Company
Cayce, South Carolina
We have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the "Company") as of December 31, 2009 and 2008, and the related consolidated statements of income, changes in equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of South Carolina Electric & Gas Company and affiliates as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
March 1,
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
South Carolina Electric & Gas Company (SCE&G, and together with its consolidated affiliates, the Company), a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA Corporation (SCANA), a South Carolina corporation. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts of SCE&G, South Carolina Fuel Company, Inc. (Fuel Company) and South Carolina Generating Company, Inc. (GENCO). Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company, and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, the Company’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Company’s condensed consolidated financial statements.
GENCO owns a coal-fired electric generating station with a 570 megawatt net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $497 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances. See also Note 5.
B. Basis of Accounting
The Company has significant cost-based, rate-regulated operations and recognizes in its financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and regulatory liabilities, summarized as follows.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections-electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings which are expected to be recovered in retail electric rates during the period January 2011 through April 2012. As a part of a settlement agreement approved by the SCPSC in April 2009, SCE&G is allowed to collect interest on the deferred balance during the recovery period.
Environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates. SCE&G is authorized to amortize $1.4 million of these costs annually.
Asset retirement obligations (ARO) and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) and conditional AROs.
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.
Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities, and the costs deferred pursuant to specific regulatory orders (see Note 3), but which are expected to be recovered through utility rates.
Other asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.
The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates. SCE&G applied costs of $10.0 million in 2009 and $7.3 million in 2008 to the reserve. See Note 2.
Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved through specific SCPSC orders. SCE&G is collecting $8.5 million annually, ending December 2013, through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.
The SCPSC or the United States Federal Energy Regulatory Commission (FERC) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. In addition, the Company has deferred in utility plant in service approximately $75.5 million of unrecovered costs related to the Lake Murray backup dam project and $70.1 million of costs related to the installation of selective catalytic reactor (SCR) technology at its Cope Station generating facility. See Note 11B. These costs are not currently being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment, or changes in accounting requirements the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.
C. Utility Plant and Major Maintenance
Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to maintenance expense.
SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) jointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G’s portion of Summer Station was approximately $1.0 billion as of December 31, 2009 and 2008 (including amounts capitalized related to the recording of AROs). Accumulated depreciation associated with SCE&G’s share of Summer Station was $538.3 million and $527.6 million as of December 31, 2009 and 2008, respectively (including amounts capitalized related to the recording of AROs). SCE&G’s share of the direct expenses associated with operating Summer Station is included in other operation and maintenance expenses and totaled $92.7 million in 2009, $87.4 million in 2008 and $86.7 million in 2007.
In addition, SCE&G and Santee Cooper are constructing two new nuclear units at the site of Summer Station that will be jointly owned in the proportions of 55 percent and 45 percent, respectively, with each party providing its own financing. SCE&G will be the operator of the new units. SCE&G’s portion of the construction work in progress for the new units was $476.5 million at December 31, 2009 and $126.7 million at December 31, 2008.
Planned major maintenance costs related to certain fossil and hydro turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Through 2013, SCE&G is authorized to collect $8.5 million annually through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2009, SCE&G incurred $17.1 million for turbine maintenance. Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage upon completion of the preceding outage. SCE&G accrued $1.1 million per month from January 2007 through June 2008 for its portion of the outage in the spring of 2008 and accrued $1.2 million per month from July 2008 through December 2009 for its portion of the outage in the fall of 2009. Total costs for the 2008 outage were $25.7 million, of which SCE&G was responsible for $17.1 million. Total costs for the 2009 outage were $32.7 million, of which SCE&G was responsible for $21.8 million. As of December 31, 2008, SCE&G had an accrued balance of $7.3 million. There was no accrued balance as of December 31, 2009.
D. Allowance for Funds Used During Construction (AFC)
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company calculated AFC using average composite rates of 7.4% for 2009, 6.0% for 2008 and 5.8% for 2007. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.
E. Revenue Recognition
The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $104.3 million at December 31, 2009 and $97.1 million at December 31, 2008.
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual hearing.
Customers subject to the purchased gas adjustment (PGA) are billed based on a fixed cost of gas determined by the SCPSC during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual hearing. In addition, included in these amounts are realized gains and losses incurred in the Company’s natural gas hedging program.
The Company’s gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment (WNA) which minimizes fluctuations in gas revenues due to abnormal weather conditions.
F. Depreciation and Amortization
The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.95% in 2009, 3.15% in 2008 and 3.13% in 2007.
The Company records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the United States Department of Energy (DOE) under a contract for disposal of spent nuclear fuel.
G. Nuclear Decommissioning
The Company’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station. The cost estimate assumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.
Under the Company’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2009, 2008 and 2007) are invested in insurance policies on the lives of certain Company and affiliate personnel. The Company transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
H. Income and Other Taxes
The Company is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including the Company, in the form of capital contributions. The Company received capital contributions under such provisions of $8.7 million in 2009 and $1.8 million in 2008.
Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Accordingly, no such taxes are included in revenues or expenses in the statements of income.
I. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
The Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.
J. Environmental
The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates.
K. Cash and Cash Equivalents
The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and notes.
L. Commodity Derivatives
SCE&G hedges gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options. SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.
M. New Accounting Matters
Effective for the year beginning January 1, 2010, the Company will adopt accounting guidance that requires an enterprise to perform an analysis to determine whether it has a controlling financial interest in a variable interest entity. The adoption of this guidance is not expected to significantly impact the Company’s results of operations, cash flows or financial position.
Effective June 30, 2009, the Company adopted new accounting guidance that makes the Company’s management responsible for subsequent-events accounting and disclosure. The adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.
Effective January 1, 2009, the Company adopted accounting guidance that requires enhanced disclosures about an entity’s derivative and hedging activities to include how derivative instruments are accounted for and the effect of such activities on the entity’s financial statements. The adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.
Effective January 1, 2009, the Company adopted accounting guidance that requires the acquiring entity in a business combination to recognize the assets acquired and the liabilities assumed at their fair values at the acquisition date and to disclose all of the information needed to evaluate and understand the nature and financial effect of the business combination. The adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.
Effective January 1, 2009, the Company adopted accounting guidance that requires entities to report noncontrolling (minority) interests in subsidiaries as equity. The adoption of this guidance did not significantly impact the Company’s results of operations or cash flows but did result in a net $11 million reduction in total equity.
Additionally, the adoption of guidance on noncontrolling interests had the effect of reclassifying earnings attributable to non-controlling interest in the consolidated statement of operations from other income and expense to separate line items. This guidance also required that net income be adjusted to include the net income attributable to the non-controlling interest, and a new separate caption for net income attributable to common shareholders be presented in the consolidated statement of operations. Thus, after adoption of this guidance, net income increased by $9 million and $7 million for the years 2008 and 2007, respectively, and net income attributable to SCE&G is equal to net income as previously reported prior to the adoption of this guidance.
SCE&G has corrected the presentation of the preferred stock not subject to purchase or sinking funds to present these preferred securities in a manner consistent with temporary equity. Although the effects are not material to previously issued balance sheets, the presentation of these amounts has been corrected as of December 31, 2008 by presenting these $106 million of preferred securities separately from common equity and eliminating the “Shareholder’s Investment” section and related total. This change had no impact on income or on cash flows for any period presented.
N. Affiliated Transactions
Carolina Gas Transmission Corporation (CGT) transports natural gas to the Company to supply certain electric generation requirements and to serve SCE&G’s retail gas customers. SCE&G had approximately $2.8 million payable to CGT for transportation services at December 31, 2009 and approximately $0.7 million in receivables, related to certain transportation refunds, at December 31, 2008.
The Company purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating Station, Urquhart Electric Generation Station and to serve its retail gas customers. Such purchases totaled approximately $160.8 million in 2009, $290.5 million in 2008 and $208.9 million in 2007. SCE&G’s payables to SEMI for such purposes were $13.3 million and $11.1 million as of December 31, 2009 and 2008, respectively.
The Company held equity-method investments in two partnerships that were involved in converting coal to synthetic fuel. The partnerships ceased operations as a result of the expiration of the synthetic fuel tax credits program at the end of 2007, and they were dissolved in 2008. The Company purchased synthetic fuel from these affiliated companies of $281.6 million in 2007. The Company made cash investments in these affiliated companies of $2.2 million in 2008 and $16.2 million in 2007.
SCE&G purchases shaft horsepower from a cogeneration facility. The facility is owned by a limited liability company (LLC) in which, prior to July 1, 2008, SCANA held an equity method investment. Transactions subsequent to June 30, 2008 were not considered to be affiliated transactions. SCE&G made affiliated purchases of shaft horsepower from the LLC of $14.7 million in 2008 and $27.7 million in 2007.
The Company participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. The Company incurred interest expense on money pool borrowings of $0.2 million in 2009 and of $4.2 million in 2008 and 2007. At December 31 2009 and December 31, 2008, the Company owed an affiliate $29.2 million and had a net receivable of $9.1 million, respectively.
O. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. RATE AND OTHER REGULATORY MATTERS
Electric
SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In April 2009, the SCPSC approved a settlement agreement between SCE&G, the South Carolina Office of Regulatory Staff (ORS), and others authorizing SCE&G to increase the fuel cost portion of its electric rates, effective with the first billing cycle of May 2009. As a part of the settlement, SCE&G agreed to spread the recovery of undercollected fuel costs over a three-year period ending April 2012, as further described in Note 1B. SCE&G is allowed to collect interest on the deferred balance.
In January 2010, SCE&G filed an application with the SCPSC requesting a 9.52% overall increase to retail electric base rates. If approved, the increase in rates would be phased in over three periods in July 2010, January 2011 and July 2011. A public hearing on this matter is scheduled to begin on May 24, 2010.
In December 2009, SCE&G submitted to the FERC for filing revised tariff sheets to change the network and point to point transmission rates under SCE&G’s Open Access Transmission Tariff. The request, if approved, would result in an annual revenue increase of $5.6 million. The requested rates utilize a cost of service formula, which departs from the traditional rate structure currently in effect.
In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the Base Load Review Act (the BLRA) to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station. The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.
In June 2009, SCE&G filed a request with the SCPSC for approval of the implementation of certain demand reduction and energy efficiency programs (DSM programs). SCE&G has requested the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM programs, along with an incentive for investing in such programs. The SCPSC has scheduled a hearing on SCE&G’s request for April 1, 2010.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the Base Load Review Act (the BLRA) seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court. A hearing for one appeal is set for March 4, 2010, and the hearing for the other appeal has not been set. SCE&G cannot predict how or when the appeals will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In January 2010, the SCPSC approved SCE&G’s request under the BLRA to approve an updated construction and capital cost schedule for the new units. The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.
In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of their review. Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011 or early 2012. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.
In a December 2007 order, the SCPSC granted SCE&G an increase in retail electric revenues of approximately $76.9 million, or 4.4%, based on a test year calculation. The order granted an allowed return on common equity of 11%. The new rates became effective January 1, 2008. In that order, the SCPSC also extended through 2015 its approval of the accelerated capital recovery plan for SCE&G’s Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year. No such additional depreciation has been recognized.
In October 2007, the SCPSC approved SCE&G’s request to increase the storm damage reserve cap from $50 million to $100 million. In addition, the SCPSC approved SCE&G’s request to apply certain transmission and distribution insurance premiums against the reserve. In more recent actions, the SCPSC also approved SCE&G’s request to apply against the reserve certain tree trimming expenditures in excess of amounts included in base rates through 2010.
Gas
The Natural Gas Rate Stabilization Act (RSA) is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. In October 2009, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $13 million under the terms of the RSA. The rate adjustment was effective with the first billing cycle of November 2009.
In October 2008, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $3.7 million under the terms of the RSA. The rate adjustment was effective with the first billing cycle of November 2008.
In October 2007, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $4.6 million under the terms of the RSA. The rate adjustment was effective with the first billing cycle in November 2007.
SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. In December 2009, in connection with the annual review of the PGA and the gas purchasing policies of SCE&G, the SCPSC determined that SCE&G’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 17 months ended July 31, 2009.
3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension and Other Postretirement Benefit Plans
The Company participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA’s policy has been to fund the plan to the extent permitted by applicable federal income tax regulations, as determined by an independent actuary.
Effective July 1, 2000 SCANA’s pension plan, which provided a final average pay formula, was amended to provide a cash balance formula for employees hired before January 1, 2000 who elected that option and for all employees hired on or after January 1, 2000. For employees who elected to remain under the final average pay formula, benefits are based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. For employees under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits.
In addition to pension benefits, the Company participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to active and retired employees. Retirees share in a portion of their medical care cost. SCANA provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.
For the years ended December 31, 2009 the Company’s net periodic benefit cost for the pension plan was $34.6 million. For the years ended December 31, 2008 and 2007, the Company’s net periodic benefit income for the pension plan was $18.3 million and $20.0 million, respectively. Net periodic benefit cost was $13.0 million, $13.0 million and $12.8 million for 2009, 2008 and 2007, respectively, for the postretirement plan.
Additionally, in February 2009, SCE&G was granted accounting orders by the SCPSC under which it is mitigating a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above that which is included in current rates for its retail electric and gas distribution regulated operations. These costs are being deferred until future rate filings, at which time the accumulated deferred costs will be addressed prospectively.
Stock Purchase Savings Plan
The Company participates in the SCANA Stock Purchase Savings Plan into which eligible employees may contribute. Eligible employees may defer up to 25% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan for 2009, 2008 and 2007 were $16.6 million, $16.1 million and $14.9 million, respectively. These matching contributions were made in the form of SCANA common stock.
Share-Based Compensation
The Company participates in the SCANA Long-Term Equity Compensation Plan (the Plan) which provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The Plan currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.
Compensation costs related to share-based payment transactions are required to be recognized in the financial statements. With limited exceptions, including those liability awards discussed below, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award.
Liability Awards
The 2007-2009 performance cycle provides for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on the performance shares. Payout of performance share awards was determined by SCANA’s performance against pre-determined measures of total shareholder return (TSR) as compared to a peer group of utilities (weighted 60%) and growth in earnings per share (as defined) (weighted 40%). Accordingly, payouts under the 2007 three-year cycle were earned for each year that performance goals were met during the three-year cycle, though payments were deferred until the end of the cycle and were contingent upon the participants still being employed by SCANA at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability. Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2010.
In the 2008-2010 performance cycle, 20% of the performance award was granted in the form of restricted (nonvested) shares, which are equity awards more fully further described below. The remaining 80% of the award was made in performance shares. The payment of performance shares for the 2008-2010 performance cycle will also be based on SCANA’s performance against pre-determined measures of TSR (weighted 50%) and the growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%).
In the 2009-2011 performance cycle, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash. The remaining 80% of the awards were made in performance shares with payment criteria identical to those awarded for the 2008-2010 performance cycle.
Compensation cost of all these liability awards is recognized over their respective three-year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities related to similar prior programs totaling $1.7 million in 2009 and $0.4 million in 2008
were paid. No such payments were made in 2007.
Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $4.5 million in 2009, $10.7 million in 2008 and $3.8 million in 2007. Fair value adjustments resulted in capitalized compensation costs of $0.9 million in 2009, $1.8 million in 2008 and $0.7 million in 2007.
Equity Awards
A summary of activity related to nonvested shares follows:
Nonvested shares were granted at a price corresponding to the opening price of SCANA common stock on the date of the grant. The Company expensed compensation costs for nonvested shares of $0.1 million in 2009 and 2008. Tax benefits and capitalized compensation costs in 2009 and 2008 were not significant. No shares were granted under the plan in 2009, and none were vested in any year presented.
A summary of activity related to nonqualified stock options follows:
No stock options have been granted since August 2002, and all options were fully vested in August 2005. No options were forfeited during any period presented. The options expire ten years after the grant date. At December 31, 2009, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 1.9 years.
The exercise of stock options during 2009 was satisfied using original issue shares, and during 2007 and 2008 such exercise was satisfied using a combination of original issue shares and open market purchases of SCANA’s common stock. For the years ended December 31, 2009 and 2008, cash realized upon the exercise of options and related tax benefits were not significant. For the year ended December 31, 2007, cash realized upon the exercise of options totaled $7.1 million, and related tax benefits credited to SCANA’s additional paid in capital (common equity) during the period totaled $1.5 million.
4. LONG-TERM DEBT
Long-term debt by type with related weighted average interest rates and maturities at December 31 is as follows:
(a) Includes $71.4 million of variable rate debt hedged by fixed rate swaps.
The annual amounts of long-term debt maturities for the years 2010 through 2014 are summarized as follows:
Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt.
5. LINES OF CREDIT AND SHORT-TERM BORROWINGS
At December 31, 2009 and 2008, SCE&G (including Fuel Company) had available the following committed lines of credit (LOC) and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
(a) The Company’s committed lines of credit serve to back-up the issuance of commercial paper or to provide liquidity support.
Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term
commercial paper or LOC advances.
SCE&G and Fuel Company have commercial paper programs in the amount of $350 million and $250 million, respectively. SCE&G has guaranteed the short-term borrowings of Fuel Company.
The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wachovia Bank, National Association and Bank of America, N. A. each provide 14.3% of the aggregate $650 million credit facilities, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%. Four other banks provide the remaining 9.6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company). In addition, a portion of the credit facilities supports SCANA’s borrowing needs. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).
The South Carolina Jobs-Economic Development Authority (JEDA) issued $35.0 million of Industrial Revenue Bonds in December 2008, the proceeds of which were loaned to SCE&G. The payment of the principal and interest on the bonds is secured by a letter of credit issued by Branch Banking and Trust Company. The bonds mature on December 1, 2038. This letter of credit expires on December 10, 2011. Similarly, JEDA issued $36.4 million of Industrial Revenue Bonds in November 2008, the proceeds of which were loaned to GENCO and guaranteed by SCANA. The bonds mature on December 1, 2038. The payment of the principal and interest on these bonds is secured by a letter of credit issued by Branch Banking and Trust Company. This letter of credit expires on November 9, 2011.
The Company pays fees to banks as compensation for maintaining committed lines of credit.
6. RETAINED EARNINGS
SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock.
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2009, $57 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
7. PREFERRED STOCK
On December 30, 2009, SCE&G redeemed all outstanding shares of its preferred stock. The fair value of the preferred shares redeemed exceeded their carrying value by approximately $2.1 million. This excess payment is reflected on the statement of income as a return to preferred shareholders within preferred stock dividends.
8. INCOME TAXES
Total income tax expense attributable to income for 2009, 2008 and 2007 is as follows:
The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows:
The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $979 million at December 31, 2009 and $890 million at December 31, 2008 are as follows:
The Company is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns. The Internal Revenue Service (IRS) has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2005 are closed for additional assessment. With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2006.
In September 2009, an income tax uncertainty was resolved in the Company’s favor upon the receipt of a favorable ruling in litigation of a state tax issue, which resulted in a refund of $15.3 million in state income taxes, plus interest. While the total of this tax benefit that will impact the effective tax rate will be $15.3 million, such impact is not expected to be material in the future years because, under regulatory accounting provisions, the tax benefit recorded is being amortized into earnings over the remaining life of property additions that gave rise to the tax benefit. No other material changes in the status of the Company’s uncertain tax positions have occurred during any period presented.
The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2009, 2008 and 2007.
9. DERIVATIVE FINANCIAL INSTRUMENTS
The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings or as a component of other comprehensive income (loss), depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries, including SCE&G. The Risk Management Committee, which is comprised of certain officers, including the Company’s Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
Commodity Derivatives
SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as New York Mercantile Exchange (NYMEX) futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.
SCE&G hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. These derivative financial instruments are not formally designated as hedges under applicable accounting guidance.
Interest Rate Swaps
The Company uses interest rate swaps to manage interest rate risk on certain debt issuances. The Company uses swaps to synthetically convert variable rate debt to fixed rate debt. In addition, in anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements which are designated as cash flow hedges. The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. Ineffective portions of changes in fair value are recognized in income.
The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the consolidated statements of cash flows.
Quantitative Disclosures Related to Derivatives
At December 31, 2009, SCE&G was party to natural gas derivative contracts for 2,365,000 dekatherms. Also at December 31, 2009, the Company was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $71.4 million.
At December 31, 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheet as follows:
(a) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses. In the
Company’s consolidated balance sheet, unrealized gain and loss positions with the same counterparty are reported as
either a net asset or liability.
The effect of derivative instruments on the statement of income is as follows:
Hedge Ineffectiveness
Other gains (losses) recognized in income representing interest rate hedge ineffectiveness totaled $1.2 million, net of tax, in 2009. These amounts are recorded within interest expense on the statement of income.
Credit Risk Considerations
Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of December 31, 2009, the Company has posted no collateral related to derivatives with contingent provisions that are in a net liability position. If all of the contingent features underlying these instruments were fully triggered as of December 31, 2009, the Company would be required to post an additional $43,258 of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2009, is $43,258.
10. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
The Company values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
There were no fair value measurements based on significant unobservable inputs (Level 3) for either date presented.
Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2009 and December 31, 2008 were as follows:
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. Early settlement of long-term debt may not be possible or may not be considered prudent.
The fair value of preferred stock as of December 31, 2008 was estimated using market quotes. At December 31, 2009, all shares of preferred stock had been redeemed. See additional disclosure at Note 7.
Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.
11. COMMITMENTS AND CONTINGENCIES
A. Nuclear Insurance
The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.6 billion. Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be $78.3 million per incident, but not more than $11.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.2 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material adverse impact on the Company’s results of operations, cash flows and financial position.
B. Environmental
In December 2009 the United States Environmental Protection Agency (EPA) issued a final finding that atmospheric concentrations of greenhouse gasses (GHG) endanger public health and welfare within the meaning of Section 202(a) of the Clean Air Act, as amended (CAA). The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions by November 2011. On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as SCE&G’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the Clean Air Interstate Rule (CAIR), which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements. SCE&G has completed installation of a selective catalytic reactor (SCR) technology at Cope Station for nitrogen oxide reduction and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction. SCE&G also is installing a wet limestone scrubber at Wateree Station. The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these scrubber projects. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
In 2005 the EPA issued the Clean Air Mercury Rule (CAMR) which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule. On February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. The Company expects the EPA will issue a new mercury emissions rule but cannot predict when such a rule will be issued or what requirements it will impose.
SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List in April 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. The EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that is expected to be completed in 2010. The site has not been remediated nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recovery, if any, is expected to be recoverable through rates.
SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and recovers them through rates (see Note 1).
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $7.7 million. In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery, through rates. At December 31, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.4 million.
C. Claims and Litigation
In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette, and Mark Rudd and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. (SCI) was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims. SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to easement grantors situated in Charleston County, South Carolina. In February 2008, the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County. In July 2008, the plaintiff’s motion to add SCI to the lawsuit as an additional defendant was granted. Trial is not anticipated before the summer of 2010. SCE&G and SCI will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material adverse impact on the Company’s results of operations, cash flows or financial condition.
D. Nuclear Generation
In 2008, SCE&G and Santee Cooper entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station. SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019. SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five year escalation rates as required by the SCPSC.
E. Operating Lease Commitments
The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2031. Rent expense totaled approximately $16.5 million in 2009, $12.7 million in 2008 and $15.8 million in 2007. Future minimum rental payments under such leases are as follows:
F. Purchase Commitments
The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended for coal supply, nuclear fuel contracts, construction projects and other commitments totaled $756.9 million in 2009, $949.8 million in 2008 and $728.3 million in 2007. Future payments under such purchase commitments are as follows:
G. Asset Retirement Obligations
The Company recognizes a liability for the fair value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations. As of December 31, 2009, the Company has recorded an ARO of approximately $111 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $347 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:
Revisions in estimated cash flows in 2008 related to the expectation of higher costs associated with coal ash disposal than had been assumed in the 2007 cash flow analysis.
12. SEGMENT OF BUSINESS INFORMATION
The Company’s reportable segments are Electric Operations and Gas Distribution. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations is primarily engaged in the generation, transmission, and distribution of electricity, and is regulated by the SCPSC and FERC. Gas Distribution is engaged in the purchase and sale, primarily at retail, of natural gas, and is regulated by the SCPSC.
Disclosure of Reportable Segments (Millions of dollars)
Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments. As a result, the Company does not allocate interest charges, income tax expense or assets other than utility plant to its segments. Interest income is not reported by segment and is not material. The Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.
The consolidated financial statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Segment Assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include the totals from the Company that are not allocated to the segments. Expenditures for Assets are adjusted for revisions to estimated cash flows related to asset retirement obligations, and totals not allocated to other segments.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
PART II,
ITEMS 9, 9A, 9A(T) AND 9B
PART III
AND
PART IV
SCANA CORPORATION
SOUTH CAROLINA ELECTRIC & GAS COMPANY
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2009, an evaluation was performed under the supervision and with the participation of SCANA Corporation’s (SCANA) management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCANA’s management, including the CEO and CFO, concluded that SCANA’s disclosure controls and procedures were effective as of December 31, 2009. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2009 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.
Management’s Evaluation of Internal Control Over Financial Reporting:
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2009, the effectiveness of such structure and procedures. This management report follows.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of SCANA Corporation (SCANA) is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA’s internal control system was designed by or under the supervision of SCANA’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), to provide reasonable assurance to SCANA’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.
SCANA’s management assessed the effectiveness of SCANA’s internal control over financial reporting as of December 31, 2009. In making this assessment, SCANA used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, SCANA’s management believes that, as of December 31, 2009, internal control over financial reporting is effective based on those criteria.
SCANA’s independent registered public accounting firm has issued an attestation report on SCANA’s internal control over financial reporting. This report follows.
ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
SCANA Corporation
Cayce, South Carolina
We have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2009 of the Company and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
March 1,
ITEM 9A(T). CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2009, an evaluation was performed under the supervision and with the participation of South Carolina Electric & Gas Company’s (SCE&G) management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCE&G’s management, including the CEO and CFO, concluded that SCE&G’s disclosure controls and procedures were effective as of December 31, 2009. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2009 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.
Management’s Evaluation of Internal Control Over Financial Reporting:
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2009, the effectiveness of such structure and procedures. This management report follows.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of South Carolina Electric & Gas Company (SCE&G) is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G’s internal control system was designed by or under the supervision of SCE&G’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), to provide reasonable assurance to SCE&G’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.
SCE&G’s management assessed the effectiveness of SCE&G’s internal control over financial reporting as of December 31, 2009. In making this assessment, SCE&G used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, SCE&G’s management believes that, as of December 31, 2009, internal control over financial reporting is effective based on those criteria.
This annual report does not include an attestation report of SCE&G’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SCE&G’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit SCE&G to provide only its management’s report in this annual report.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
A list of SCANA’s executive officers is in Part I of this annual report at page 24. The other information required by Item 10 is incorporated herein by reference to the captions "NOMINEES FOR DIRECTORS," "CONTINUING DIRECTORS," "BOARD MEETINGS-COMMITTEES OF THE BOARD," "GOVERNANCE INFORMATION - SCANA’s Code of Conduct & Ethics" and "OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA’s definitive proxy statement for the 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to the captions “COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION,” “COMPENSATION DISCUSSION AND ANALYSIS,” “COMPENSATION COMMITTEE REPORT,” “SUMMARY COMPENSATION TABLE,” “2009 GRANTS OF PLAN-BASED AWARDS,” “OUTSTANDING EQUITY AWARDS AT 2009 FISCAL YEAR-END,” “2009 OPTION EXERCISES AND STOCK VESTED,” “PENSION BENEFITS,” “2009 NONQUALIFIED DEFERRED COMPENSATION,” and “POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL,” under the heading “EXECUTIVE COMPENSATION” and the heading “DIRECTOR COMPENSATION” in SCANA’s definitive proxy statement for the 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information required by Item 12 is incorporated herein by reference to the caption "SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" in SCANA’s definitive proxy statement for the 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
Equity securities issuable under SCANA’s compensation plans at December 31, 2009 are summarized as follows:
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated herein by reference to the caption “RELATED PARTY TRANSACTIONS” in SCANA’s definitive proxy statement for the 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
SCANA: The information required by Item 14 is incorporated herein by reference to "PROPOSAL 3 - APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM" in SCANA’s definitive proxy statement for the 2010 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities and Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
SCE&G: The Audit Committee Charter requires the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the independent registered accounting firm. Pursuant to a policy adopted by the Audit Committee, its Chairman may pre-approve the rendering of services on behalf of the Audit Committee. Decisions by the Chairman to pre-approve the rendering of services are presented to the Audit Committee at its next scheduled meeting.
Independent Registered Public Accounting Firm’s Fees
The following table sets forth the aggregate fees, all of which were approved by the Audit Committee, charged to SCE&G and its consolidated affiliates for the fiscal years ended December 31, 2009 and 2008 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.
(1)
Fees for audit services billed in 2009 and 2008 consisted of audits of annual financial statements, comfort letters, consents and other services related to Securities and Exchange Commission filings and accounting research.
(2) Fees primarily for employee benefit plan audits for 2008 and 2007.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed or furnished as a part of this Form 10-K:
(1) Financial Statements and Schedules:
The Report of Independent Registered Public Accounting Firm on the financial statements for SCANA and SCE&G are listed under Item 8 herein.
The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein.
The financial statement schedules filed as part of this report for SCANA and SCE&G are included below.
(2) Exhibits
Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission (SEC) and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.
Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA’s employee stock purchase plan will be furnished under cover of Form 11-K to the SEC when the information becomes available.
As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries and of SCE&G, for itself and its consolidated affiliates, have been omitted and SCANA and SCE&G agree to furnish a copy of such instruments to the SEC upon request.
Schedule II-Valuation and Qualifying Accounts
(in millions)
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.
/s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board,
President, Chief Executive Officer and Director (Principal Executive Officer)
/s/J. E. Addison
J. E. Addison, Senior Vice President
and Chief Financial Officer
(Principal Financial Officer)
/s/J. E. Swan, IV
J. E. Swan, IV, Controller
(Principal Accounting Officer)
*Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
DATE:
March 1, 2010
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries or consolidated affiliates thereof.
/s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
/s/J. E. Addison
J. E. Addison, Senior Vice President
and Chief Financial Officer
(Principal Financial Officer)
/s/J. E. Swan, IV
J. E. Swan, IV, Controller
(Principal Accounting Officer)
*Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
DATE:
March 1, 2010
EXHIBIT INDEX
* Management Contract or Compensatory Plan or Arrangement