SCANA CORP
ITEM 1. BUSINESS
CORPORATE STRUCTURE
SCANA, a holding company, owns the following direct, wholly-owned subsidiaries:
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.
GENCO owns Williams Station and sells electricity solely to SCE&G.
Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances.
PSNC Energy purchases, sells and transports natural gas to retail customers.
CGT transports natural gas in South Carolina and southeastern Georgia.
SCI provides fiber optic communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia.
SEMI markets natural gas, primarily in the Southeast, and provides energy- related risk management services. SCANA Energy, a division of SEMI, markets natural gas in Georgia’s retail market.
ServiceCare, Inc. provides service contracts on home appliances and heating and air conditioning units.
SCANA Services, Inc. provides administrative, management and other services to SCANA’s subsidiaries and business units.
SCANA is incorporated in South Carolina, as is each of its direct, wholly- owned subsidiaries. In addition to the subsidiaries above, SCANA owns two other energy-related companies that are insignificant.
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, 2012 and 2011 of 5,889 and 5,877, 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, 2012 and 2011 of 3,202 and 3,173, 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 (which is not intended as an active hyperlink) 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 664,000 customers and the purchase, sale and transportation of natural gas to approximately 317,000 customers (each as of December 31, 2011). SCE&G’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 22,600 square miles. More than 3.2 million persons live in the counties where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries served by SCE&G include chemicals, educational services, paper products, food products, lumber and wood products, health services, textile manufacturing, rubber and miscellaneous plastic products and fabricated metal products.
GENCO owns Williams Station and sells electricity solely to SCE&G.
Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances.
PSNC Energy purchases, sells and transports natural gas to approximately 487,000 residential, commercial and industrial customers (as of December 31, 2011). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The predominant industries served by PSNC Energy include educational services, food products, health services, chemicals, non-woven textiles and construction-related materials.
CGT operates as an open access, transportation-only interstate pipeline company regulated by FERC. CGT operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGT also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transco in Cherokee and Spartanburg counties, South Carolina. CGT’s customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SEMI (which markets natural gas to industrial and sale for resale customers, primarily in the Southeast), municipalities, county gas authorities, federal and state agencies, marketers, power generators and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, 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 approximately 455,000 customers (as of December 31, 2011, and includes approximately 80,000 customers in its regulated division) in Georgia’s natural gas market. SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas has been renewed by the GPSC through August 31, 2014. 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 Georgia.
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 2012-2014, 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 2.87, 2.92, 2.84, 3.04 and 3.03 for the years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively. SCE&G’s ratios of earnings to fixed charges were 3.13, 3.18, 3.25, 3.51 and 3.40 for the same periods.
ELECTRIC OPERATIONS
Electric Sales
SCE&G’s sales of electricity and margins earned from the sale of electricity by customer classification as percentages of electric revenues for 2010 and 2011 were as follows:
Sales for resale include sales to three municipalities and two electric cooperatives. Sales under NMST during 2011 include sales to seven investor-owned utilities or registered marketers and three federal/state electric agencies. During 2010 sales under the NMST included sales to nine investor-owned utilities or registered marketers, two electric cooperatives and two federal/state electric agencies.
During 2011 SCE&G recorded a net increase of approximately 3,600 electric customers (growth rate of 0.5%), increasing its total electric customers to approximately 664,000 at year end.
For the period 2012-2014, SCE&G projects total territorial KWh sales of electricity to increase 0.7% annually (assuming normal weather), total electric customer base to increase 1.6% annually and territorial peak load (summer, in MW) to increase 1.0% 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 605 MW.
SCE&G’s transmission system, which extends over a large part of the central, southern and southwestern portions of South Carolina, interconnects with Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Georgia Power Company, Oglethorpe Power Corporation and the Southeastern Power Administration’s Clarks Hill (Thurmond) Project. SCE&G, Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Dominion Virginia Power and ALCOA Power Generating, Inc. (Yadkin Division), are members of VACAR, one of several geographic divisions within the SERC. SERC is one of eight regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by FERC. 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 2009-2011 follow:
The sources and percentages of total MWh generation by each category of fuel for the years 2009-2011 and the estimates for the years 2012-2014 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.
Coal is obtained through long-term supply contracts and spot market purchases. Long-term contracts exist with suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 3.5 million tons annually, which is substantially all expected coal purchases for 2012. Sulfur restrictions on the contract coal range from 1% to 2%. These contracts expire at various times through 2014. Spot market purchases are expected to continue when needed or when prices are believed to be favorable.
SCANA and SCE&G believe that SCE&G’s operations comply with all applicable regulations relating to the discharge of sulfur dioxide and nitrogen oxide. See additional discussion at Environmental Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation.
In addition to the above-described contracts for fuel fabrication and related services, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates in the next 11 years. SCE&G believes that it will be able to renew contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of its nuclear generating units.
SCE&G can store spent nuclear fuel on-site until at least 2017 and expects to expand its storage capacity to accommodate the spent fuel output for the life of Summer Station Unit 1 through dry cask storage or other technology as it becomes available. In addition, Summer Station Unit 1 has sufficient on-site storage capacity to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract with the DOE regarding disposal of spent fuel, see Hazardous and Solid Wastes within the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
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 2010 and 2011 were as follows:
For the three-year period 2012-2014, SCANA projects total consolidated sales of regulated natural gas in DTs to increase 0.9% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 1.2%, commercial of 0.9% and industrial of 0.8%.
For the three-year period 2012-2014, SCE&G projects total consolidated sales of regulated natural gas in DTs to increase 0.4% annually (assuming normal weather). Annual projected increases over such period in DT sales include residential of 0.4%, commercial of 0.3% and industrial of 1.1%.
For the three-year period 2012-2014, SCANA’s and SCE&G’s total consolidated regulated natural gas customer base is projected to increase annually 1.5% and 1.2%, respectively. During 2011 SCANA recorded a net increase of approximately 8,800 regulated gas customers (growth rate of 1.1%), increasing its regulated gas customers to approximately 804,000. Of this increase, SCE&G recorded a net increase of approximately 3,300 gas customers (growth rate of 1.1%), increasing its total gas customers to approximately 317,000 (as of December 31, 2011).
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 2013), Transco (expiring in 2013 and 2017) and CGT (expiring in 2012, 2023 and 2026). 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 424,429 DT from CGT. Additional natural gas volumes may be delivered to SCE&G’s system as capacity is available through interruptible transportation.
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 78,083 DT.
SCE&G purchased natural gas at an average cost of $5.88 per MCF during 2011 and $6.38 per MCF during 2010.
SCE&G was allocated 5,437 MMCF of natural gas storage capacity on Southern Natural and Transco. Approximately 4,213 MMCF of gas were in storage on December 31, 2011. 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 1,759 MMCF (liquefied equivalent) of gas were in storage on December 31, 2011.
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 281,110 DT from Transco and 7,331 DT from Dominion.
PSNC Energy purchased natural gas at an average cost of $5.54 per DT during 2011 compared to $5.95 per DT during 2010.
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 12,000 MMCF of gas were in storage under these agreements at December 31, 2011. 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 800 MMCF (liquefied equivalent) of gas were in storage at December 31, 2011. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,200 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2011.
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 approximately 455,000 customers (as of December 31, 2011) in Georgia’s natural gas market. SCANA Energy’s total customer base represents an approximate 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 FERC as to certain acquisitions and other matters.
SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.
GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.
PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.
CGT is subject to the jurisdiction of FERC as to transportation rates, service, accounting and other matters.
SCANA Energy is regulated by the GPSC through its certification as a natural gas marketer in Georgia and specifically is subject to the jurisdiction of the GPSC as to retail prices for customers served under the regulated provider contract.
SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting. See the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $150 million of such short-term indebtedness. The authority to make such issuances will expire in October 2012.
The RSA allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.SCE&G is presently operating the Saluda project under an annual license (scheduled to expire in August) while its long-term re-licensing application is being reviewed by FERC.
SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The licenses expire as follows:
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 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.
SCE&G’s retail electric rates include certain costs associated with the Company’s DSM Programs as authorized by the SCPSC. More specifically, these costs include the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers and it will continue on a pilot basis unless modified or terminated by the SCPSC.
PSNC Energy is authorized by the NCUC to utilize a CUT which allows PSNC Energy to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption whether impacted by weather or other factors.
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.
In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflected the removal of the contingency reserve and incorporated then identifiable capital costs of $173.9 million (in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.
On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed in the OTHER MATTERS - Nuclear Generation section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 1 of the consolidated financial statements (e.g., those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site).
Fuel Cost Recovery Procedures
The SCPSC’s fuel cost recovery procedure determines the fuel component in SCE&G’s retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any over-collection or under-collection from the preceding 12-month period. The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, mercury and particulates. SCE&G may request a formal proceeding concerning its fuel costs at any time should circumstances dictate such a review.
SCE&G’s retail electric rates are established in part 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 February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011. On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. The next annual hearing to review base rates for fuel costs is scheduled for March 22, 2012.
SCE&G’s natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.
PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost. The Rider D rate mechanism also allows it to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.
PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.
In January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in February 2012.
In December 2011, in connection with PSNC Energy’s 2011 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2011. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting that the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will have a material effect on the Company’s results of operations, cash flows, or financial condition.
In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2011.
In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.
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 10 to the consolidated financial statements for SCANA and SCE&G.
OTHER MATTERS
For a discussion of SCE&G’s insurance coverage for Summer Station Unit 1and the New Units, see Note 10 to the consolidated financial statements for SCANA and SCE&G.
ITEM 1A. RISK FACTORS
The risk factors that follow relate in each case to SCANA and its subsidiaries, and where indicated the risk factors also relate to SCE&G and its consolidated affiliates.
Commodity price changes, delays and other factors may affect the operating cost, capital expenditures and competitive positions of the Company’s and Consolidated SCE&G’s energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.
Our energy businesses are sensitive to changes in coal, natural gas, oil and other commodity prices (as well as their transportation costs) and availability. Any such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. Consolidated SCE&G is permitted to recover the prudently incurred cost of fuel (including transportation) used in electric generation through retail customers’ bills, but fuel cost increases affect electric prices and therefore the competitive position of electricity against other energy sources. In addition, when natural gas prices are low enough relative to coal to require the dispatch of gas-fired electric generation ahead of coal-fired electric generation, higher inventories of coal, with related increased carrying costs, may result. This may adversely affect our results of operations, cash flows and financial position.
In the case of regulated natural gas operations, costs prudently incurred for purchased gas and pipeline capacity may be recovered through retail customers’ bills. However, increases in gas costs affect total retail prices and therefore the competitive position of gas relative to electricity and other forms of energy. Gas cost increases also may result in lower usage by customers unable to switch to alternate fuels. Increases in fuel costs may also result in higher prices for and thus lower usage of electricity by customers.
Certain construction-related commodities, such as copper and aluminum used in our transmission and distribution lines and in our electrical equipment, and steel, concrete and rare earth elements, have experienced significant price fluctuations due to changes in worldwide demand. To operate our air emissions control equipment, we use significant quantities of ammonia, limestone and lime. With EPA-mandated industry-wide compliance requirements for air emissions controls, demand for these reagents, combined with the demand for low sulfur coal, may result in higher costs for coal and reagents used for compliance purposes.
The costs of large capital projects, such as the Company’s and Consolidated SCE&G’s construction for environmental compliance and its construction of the New Units and associated transmission, are significant and are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of the projects.
The Company’s and Consolidated SCE&G’s businesses are capital intensive and require significant investments in energy generation and in other internal infrastructure projects, including projects for environmental compliance. For example, SCE&G and Santee Cooper have agreed to jointly own, design, construct and operate the New Units, which will be two 1,117-megawatt nuclear units at SCE&G’s Summer Station, in pursuit of which they have committed and are continuing to commit significant resources towards project development, permitting, site preparation and long lead-time procurement. Substantial additional resources will be required for the construction and operation of the New Units upon receipt of requisite approvals. In addition, planning and construction of significant new transmission resources are necessary to support the New Units and are under way as an integral part of the project. Achieving the intended benefits of any large construction project is subject to many uncertainties. For instance, the ability to stay within established budgets and timeframes may be affected by many variables, such as the regulatory and legal processes associated with securing permits and licenses within projected timeframes, the availability of labor and materials at estimated costs, the availability and cost of financing, and weather. There also may be contractor or supplier performance issues or adverse changes in their creditworthiness, and unforeseen difficulties meeting critical regulatory requirements. There may be unforeseen engineering problems or unanticipated changes in project design or scope. Our ability to complete construction projects (including new baseload generation) as well as our ability to maintain current operations at reasonable cost could be affected by the availability of key components or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, new or enhanced environmental requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. Furthermore, joint venture projects, such as the current construction of the New Units, are subject to the risk that one or more of the joint venture partners becomes either unable or unwilling to continue to fund project financial commitments, new partners cannot be secured at equivalent financial terms, or changes in the joint venture make-up will increase project costs and/or delay the completion. To the extent that delays occur, costs become unrecoverable, or we otherwise become unable effectively to manage our capital projects our results of operations, cash flows and financial condition may be adversely affected.
The use of derivative instruments could result in financial losses and liquidity constraints. The Company and Consolidated SCE&G do not fully hedge against financial market risks or price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.
The Company and Consolidated SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. 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 strives 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.
Furthermore, recent federal legislation (Dodd-Frank) affects the use and reporting of derivative instruments. The regulations under this new legislation are still being finalized and their impact on the use of derivative instruments by the Company and Consolidated SCE&G cannot be determined at this time.
Changing and complex laws and regulations to which the Company and Consolidated SCE&G are subject could adversely affect revenues, increase costs, or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.
The Company and Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, IRS, EPA and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by agencies of the state governments of South Carolina, North Carolina and Georgia, including regulatory agencies, state environmental commissions, and state employment commissions. Accordingly, the Company and Consolidated SCE&G must comply with extensive federal, state and local laws and regulations. Such governmental oversight and regulation broadly and materially affect the operation of our business. In addition to many other aspects of our business, these requirements impact the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our transmission system, the physical and cyber security of key assets, customer conservation through demand-side management programs, information security, the issuance of securities and borrowing of money, financial reporting, interaction among affiliates, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or Consolidated SCE&G’s businesses.
The Company and Consolidated SCE&G are subject to extensive rate regulation which could adversely affect operations. In particular, SCE&G’s electric operations in South Carolina and the Company’s gas distribution operations in South Carolina and North Carolina are regulated by state utilities commissions. The Company’s interstate gas pipeline, SCE&G’s electric transmission system and Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the FERC, NRC and SCPSC. 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 market conditions evolve. Although we believe that we have constructive relationships with the regulators, our ability to obtain rate treatment that will allow us to maintain reasonable rates of return is dependent upon regulatory determinations, and there can be no assurance that we will be able to implement rate adjustments when sought.
The Company and Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and which may impact our business plans or expose us to environmental liabilities.
The Company and Consolidated SCE&G are subject to extensive federal, state and local environmental laws and regulations, including those relating to water quality and air emissions (such as reducing nitrogen oxide, sulfur dioxide, mercury and particulate matter). Some form of regulation may be forthcoming at the federal, and possibly state, levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. A number of bills have been introduced in Congress that seek to 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. On February 16, 2012, the EPA issued the finalized MATS for power plants that requires reduced emissions from new and existing coal and oil-fired electric utility steam generating facilities. The EPA has proposed requirements for cooling water intake structures to meet BACT, andthe EPA presently is drafting a final rule regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA has announced that it expects to overhaul the Clean Water Act rules governing effluent limitation standards for coal-fired power plants.
Compliance with these environmental laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emissions fees and permitting at our facilities. These expenditures have been significant in the past and are expected to continue or even increase in the future. Changes in compliance requirements or more restrictive interpretations by governmental authorities of existing requirements may impose additional costs on us (such as the clean-up of MGP sites or additional emission allowances) or require us to incur additional capital expenditures or curtail some of our cost savings activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated renewable portfolio standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could negatively impact our industry, our business and our results of operations and financial position, especially if emissions or discharge limits are reduced or more onerous permitting requirements or additional regulatory requirements are imposed.
Renewable and/or alternative electric generation portfolio standards may be enacted at the federal or state level. Some states already have them, though currently South Carolina does not. Such standards could direct us to build or otherwise acquire generating capacity derived from renewable/alternative energy sources (generally, renewable energy such as biomass, solar, wind and tidal, and excluding fossil fuels, nuclear or hydro facilities). Such renewable/alternative energy may not be readily available in our service territories, if at all, and could be extremely costly to build, acquire, and 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 at the federal level or in South Carolina or their specifics if adopted, compliance with such potential portfolio standards could significantly impact our industry, our capital expenditures, and our results of operations and financial position.
The Company and Consolidated SCE&G are vulnerable to interest rate increases which would increase our borrowing costs, and may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.
The Company and Consolidated SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company’s and Consolidated SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.
The Company’s and SCE&G’s ability to draw on our respective bank revolving credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments and on our ability to timely renew such facilities. Those banks may not be able to meet their funding commitments to the Company or Consolidated SCE&G if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time. Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.
Disruptions in the capital markets and its actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial position, including its shareholders’ equity.
A downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect our ability to access capital and to operate our businesses, thereby adversely affecting results of operations, cash flows and financial condition.
Various rating agencies rate SCANA’s long-term senior unsecured debt, SCE&G’s long-term senior secured debt and the long-term senior unsecured debt of PSNC Energy as investment grade. In addition, ratings agencies maintain ratings on the short-term debt of SCANA, SCE&G, Fuel Company (which ratings are based upon the guarantee of SCE&G) and PSNC Energy. If these rating agencies were to lower the outlook or downgrade any of these ratings, particularly to below investment grade, borrowing cost on new issuances would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease.
One rating agency, by action taken in 2011, downgraded both the short-term and senior unsecured long-term debt of SCANA. These downgrades have increased SCANA’s short-term borrowing rate and decreased the average maturity of its short-term debt, and may have the effect of increasing SCANA’s long-term borrowing rate. Although access to the short-term market has not been adversely impacted, this could change under different market conditions.
SCANA’s leverage ratio of long- and short-term debt to capital was approximately 58% at December 31, 2011. SCANA has publicly announced its desire to maintain its leverage ratio at levels between 54% and 57%, but SCANA’s ability to achieve and maintain those levels depends on a number of factors. In the future, if SCANA is not able to achieve and maintain its leverage ratio within the desired range, the Company’s debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.
Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.
The Company has delivered less gas and received lower prices for natural gas in deregulated markets, and consequently earned less income when weather conditions have been milder than normal. During 2010, the SCPSC approved SCE&G’s implementation of an eWNA on a pilot basis. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and SCE&G if the eWNA is not extended on a permanent basis. In addition, for the Company and Consolidated SCE&G, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.
Natural disasters (such as the 2011 earthquake and tsunami in Japan) or man-made mishaps (such as the San Bruno, California natural gas transmission pipeline failure or the Kingston, Tennessee coal ash pond failure) could have direct significant impacts on the Company and Consolidated SCE&G and on our key contractors and suppliers or could indirectly impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial position, operating expenses, and cash flows.
Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.
The utility industry has been undergoing structural change for a number of years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales has been introduced on a national level. Some states have also mandated or encouraged competition at the retail level. Increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, the Company’s and Consolidated SCE&G’s generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets would be required.
The Company and SCE&G are subject to risks associated with changes in business and economic climate which could adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.
Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Some economic sectors important to our customer base may be particularly affected. Adverse events, economic or otherwise, may also affect the operations of key customers. Such events may result in the loss of customers, changes in customer usage patterns and in the failure of customers to make timely payments to us. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally or legislative or regulatory actions. Budget cutbacks also adversely affect funding levels of federal and state support agencies and non-profit organizations that assist low income customers with bill payments.
In addition, conservation efforts and/or technological advances may cause or enable customers to significantly reduce their usage of the Company’s and SCE&G’s products and adversely affect sales, sales growth, and customer usage patterns.
Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed.
Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.
Critical processes or systems in the Company’s or Consolidated SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission line failure, information systems failure or security breach, the effects of drought (including reduced water levels) on the operation of emission control or other generation equipment, and the effects of a pandemic or terrorist attack on our workforce or facilities or on the ability of vendors and suppliers to maintain services key to our operations.
In particular, as the operator of power generation facilities, many of which entered service prior to 1985 and may be difficult to maintain, Consolidated 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 Consolidated SCE&G purchasing emission allowances or replacement power at market rates, if such allowances and replacement power are available at all. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. These purchases are subject to state regulatory prudency reviews for recovery through rates. Similarly, a gas transmission or distribution line failure of the Company or Consolidated SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers. Events such as these could entail substantial repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company’s revenues, results of operations, and financial condition.
SCANA’s ability to pay dividends and to make payments on SCANA’s debt securities may be limited by covenants in certain financial instruments and by the financial results and condition of its subsidiaries, thereby adversely impacting the valuation of our common stock and our access to capital .
We are a holding company that conducts substantially all of our operations through our subsidiaries. Our assets consist primarily of investments in subsidiaries. Therefore, our ability to meet our obligations for payment of interest and principal on outstanding debt and to pay dividends to shareholders and corporate expenses depends on the earnings, cash flows, financial condition and capital requirements of our subsidiaries, and the ability of our subsidiaries, principally Consolidated SCE&G, PSNC Energy and SEMI to pay dividends or to advance or repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.
A significant portion of Consolidated SCE&G’s generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition. These risks will increase as the New Units are developed.
In 2011, Summer Station Unit 1, operated by SCE&G, provided approximately 5 million MWh, or 19% of our generation capacity. If the New Units are completed, our generating capacity and the percentage of total generating capacity represented by nuclear sources is expected to increase. Hence, 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 nuclear fuel and the storage of spent nuclear 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 Consolidated SCE&G’s operations and financial performance.
Implementation of our strategic plan and growth strategy requires that we attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate and grow our business. Competition for these employees is high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance.
The Company and Consolidated SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial position, and access to capital.
From time to time, the Company and Consolidated SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plant and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved by regulators), to the detriment of the Company or Consolidated SCE&G. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or Consolidated SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial position, as well as limit our ability to access capital.
The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure to adhere to high standards of compliance with laws and regulations, ethical conduct, operational effectiveness, and safety of employees, customers and the public. These risks could adversely affect the valuation of our common stock and the Company’s and Consolidated SCE&G’s access to capital.
The Company and Consolidated SCE&G are committed to comply with all laws and regulations, to focus on the safety of employees, customers and the public, to maintain the privacy of information related to our customers and employees and to maintain effective communications with the public and key stakeholder groups, particularly during emergencies and times of crisis. The Company and Consolidated SCE&G also are committed to operational excellence and, through our Code of Conduct and Ethics, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments may subject the Company and Consolidated SCE&G not only to fraud, litigation and financial loss, but also to reputational risk that could adversely affect the valuation of SCANA’s stock, adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not Applicable
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.
(1) Represents SCE&G’s two-thirds portion of Summer Station Unit 1 (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 Kapstone Charleston Kraft, 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 64 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 2010 and have aggregate net generating capacity of 355 MW.
SCE&G owns 441 substations having an aggregate transformer capacity of 30 million KVA. The transmission system consists of 18,295 miles of lines, and the distribution system consists of 6,763 pole miles of overhead lines and trench miles of underground lines.
NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES
SCE&G’s natural gas system consists of 16,549 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 1,469 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 606 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy’s distribution system consists of 10,201 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly-owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition,
PSNC Energy owns, through a wholly-owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.
ITEM 3. LEGAL PROCEEDINGS
Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2011, are described below. These issues affect the Company and, to the extent indicated, also affect Consolidated SCE&G.
In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the CAIR, which required 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. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with the CSAPR and the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide. This new standard may require some of SCE&G’s smaller coal-fired units to reduce their sulfur dioxide emissions to a level to be determined by EPA and/or DHEC. The costs incurred to comply with this new standard are expected to be recovered through rates.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2014 and will cost an additional $8.3 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.
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 $3.1 million, the estimated remaining liability at December 31, 2011. 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, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. This settlement did not have a material impact on the Company’s results of operations, cash flows or financial condition.
SCANA and SCE&G are also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on their respective results of operations, cash flows or financial condition.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable
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.
* Indicates position held at least since March 1, 2007.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
COMMON STOCK INFORMATION
SCANA Corporation:
Price Range (New York Stock Exchange Composite Listing):
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, 2012 there were 130,295,890 shares of SCANA common stock outstanding which were held by approximately 29,134 shareholders of record. For a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2011, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
SCANA declared quarterly dividends on its common stock of $.485 per share in 2011 and $.475 per share in 2010. On February 15, 2012, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.495 per share, an increase of 2.1%. The new dividend is payable April 1, 2012 to shareholders of record on March 9, 2012. For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources-Financing Limits and Related Matters and Note 3 to the consolidated financial statements for SCANA.
SCE&G:
All of SCE&G’s common stock is owned by SCANA, and no established public trading market exists for SCE&G common stock. During 2011 and 2010, SCE&G declared quarterly dividends on its common stock in the following amounts:
On February 15, 2012, SCE&G declared dividends on its common stock of $51.6 million.
For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources-Financing Limits and Related Matters and Note 3 to the consolidated financial statements for SCE&G.
ITEM 6. SELECTED FINANCIAL DATA
SCANA CORPORATION
Page
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and sale of electricity in parts of South Carolina and in the purchase, transmission and sale of natural gas in portions of North Carolina and South Carolina. Through a wholly-owned nonregulated subsidiary, SCANA markets natural gas to retail customers in Georgia and to wholesale customers primarily in the southeast. Other wholly- owned nonregulated subsidiaries provide fiber optic and other telecommunications services and provide service contracts to homeowners on certain home appliances and heating and air conditioning units. A service company subsidiary of SCANA provides administrative, management and other services to SCANA and its subsidiaries.
The following map indicates areas where the Company’s significant business segments conduct their activities, as further described in this overview section.
The following percentages reflect revenues and income available to common shareholders earned by the Company’s regulated and nonregulated businesses and the percentage of total assets held by them.
Key Earnings Drivers and Outlook
During 2011, economic growth showed modest signs of improvement in the southeast. Significant industrial announcements were made in the Company’s South Carolina service territory during the year. In addition, residential and commercial customer growth rates in the Company’s regulated businesses were positive, though customer usage by existing customers continued to decline. Unemployment rates for the states in which the Company primarily provides service also showed some improvement, though unemployment remains high and continues to slow the pace of economic recovery in the Southeast.
Over the next five years, key earnings drivers for the Company will be additions to rate base at its regulated subsidiaries, consisting primarily of capital expenditures for new generating capacity, environmental facilities and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage in each of the regulated utility businesses, earnings in the natural gas marketing business in Georgia and the level of growth of operation and maintenance expenses and taxes.
Electric Operations
The electric operations segment is comprised of the electric operations of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 2011, SCE&G provided electricity to approximately 664,000 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, certain fossil fuels and emission allowances.
Operating results for electric operations are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity is 10.7% for non-BLRA expenditures, and 11.0% for BLRA-related expenditures. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.
New Nuclear Construction
SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two 1,117-MW nuclear generation units to be constructed at the site of Summer Station, 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. Under these agreements, SCE&G will have the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online.
SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction of the New Units. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. The successful completion of the New Units would result in a substantial increase in the Company’s utility plant in service. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to the Company.
As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units.
The Consortium has recently performed an impact study, at SCE&G’s request, related to various cost and timing alternatives arising from the delay in the issuance date of the COL from mid-2011, which was the date assumed when the EPC Contract was signed in 2008, to the early-2012 issuance date currently anticipated by SCE&G. SCE&G has recently
informed the Consortium that it intends to pursue the alternative that would delay the substantial completion date of the first New Unit and accelerate the substantial completion date for the second New Unit and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.
In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactor to be used for the New Units. This certification is a necessary step before the NRC can issue a COL for the New Units. In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.
See additional discussion at OTHER MATTERS - Nuclear Generation.
Environmental
Significant federal legislative initiatives related to energy were unsuccessful in 2011, and the Company expects such legislative initiatives will be hampered through 2012, due to each chamber of Congress being controlled by different political parties. The EPA, however, did issue new rules in 2011 related to air quality, including CSAPR and MATS, which require reductions in
power plant emissions of sulfur dioxide, nitrogen oxide and mercury, among other substances. Though implementation of CSAPR was stayed by the United States Court of Appeals for the District of Columbia pending judicial review, the Company cannot predict the outcome that judicial review will have on the rule’s implementation. In 2012, additional significant regulatory initiatives by the EPA and other federal agencies will likely proceed. These initiatives may require the Company to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. The Company cannot predict whether such initiatives will be enacted, and if they are, the conditions they would impose on utilities.
The EPA has stated its intention to propose, in late 2012, new federal regulations affecting the management and disposal of CCR, such as ash. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. The EPA is also expected to issue regulations during 2012 for cooling water intake structures to meet BACT at existing power generating stations. 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, comprised of the local distribution operations of SCE&G and PSNC Energy, is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of North Carolina and South Carolina. At December 31, 2011 this segment provided natural gas to approximately 804,000 customers in areas covering 34,600 square miles.
Operating results for gas distribution are primarily influenced by customer demand for natural gas rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity.
Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact the Company’s ability to retain large commercial and industrial customers. One effect of the sluggish economy has been an overall decrease in demand for natural gas which, coupled with discoveries of shale gas in the United States, resulted in significantly lower prices for this commodity in 2010 and 2011. Low natural gas commodity prices are expected to continue in 2012 and beyond.
Retail Gas Marketing
SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to approximately 455,000 customers throughout Georgia (as of December 31, 2011, and includes approximately 80,000 customers in its regulated division described below). SCANA Energy’s total customer base represents an approximate 30% share of the customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. SCANA Energy’s competitors include an affiliate of a large energy company with experience in Georgia’s energy market, as well as several electric membership cooperatives. SCANA Energy’s ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors.
As Georgia’s regulated provider, SCANA Energy provides service to low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC. SCANA Energy receives funding from the Universal Service Fund to offset some of the bad debt associated with the low-income group. SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas has been renewed by the GPSC through August 31, 2014. SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us (which is not intended as an active hyperlink; the information on the GPSC website is not part of this or any other report filed with the SEC).
SCANA Energy and SCANA’s other natural gas distribution and marketing segments maintain gas inventory and also utilize forward contracts and other financial instruments, including commodity swaps and futures contracts, to manage their exposure to fluctuating commodity natural gas prices. See Note 6 to the consolidated financial statements. As a part of this risk management process, at any given time, a portion of SCANA’s projected natural gas needs has been purchased or otherwise placed under contract. Since SCANA Energy operates in a competitive market, it may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability. Further, there can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve.
Energy Marketing
The divisions of SEMI excluding SCANA Energy comprise the energy marketing segment. This segment markets natural gas primarily in the southeast and provides energy-related risk management services to customers.
The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control growth of costs. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth. In addition, certain pipeline capacity available for Energy Marketing to serve industrial and other customers is dependent upon the market share held by SCANA Energy in the retail market.
RESULTS OF OPERATIONS
·
2011 vs 2010
Basic earnings per share increased in 2011 due to higher electric margin of $.42 and lower operating expenses of $.06. These increases were partially offset by lower gas margin of $.13, higher depreciation expense of $.06, higher property taxes of $.06, dilution from additional shares outstanding of $.07 and higher interest expense of $.14.
·
2010 vs 2009
Basic earnings per share increased in 2010 due to higher electric margin (excluding the effect of the $17.4 million adjustment described at “Electric Operations”) of $.60 and higher gas margin of $.15. These increases were partially offset by dilution from additional shares outstanding of $.09, higher operating expense of $.32, higher interest expense of $.09, net of preferred stock dividends, and $.11 due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in favor of the Company in 2009. In late 2009 SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.
Diluted Earnings Per Share
In May 2010, SCANA entered into equity forward contracts for approximately 6.6 million common shares. During periods when the average market price of SCANA’s common stock is above the per share adjusted forward sales price, the
Company computes diluted earnings per share giving effect to this dilutive potential common stock utilizing the treasury stock method.
Pension Cost
Pension cost was recorded on the Company’s income statements and balance sheets as follows:
Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension cost related to retail electric and gas operations that otherwise would have been charged to expense. These costs will be deferred until such time as future rate recovery is provided for by the SCPSC.
No contribution to the pension trust was necessary, nor did limitations on benefit payments apply, in or for any period reported.
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 3.9% of income before income taxes in 2011, 5.6% in 2010 and 9.8% in 2009.
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows:
·
2011 vs 2010
Margin increased by $49.0 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA and by $34.5 million due to an SCPSC-approved increase in retail electric base rates in July 2010. Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order in connection with SCE&G’s annual fuel cost proceeding. These increases were partially offset by $12 million due to the effects of weather in 2010 before the implementation of the SCPSC-approved eWNA and by lower customer usage of $8.7 million.
·
2010 vs 2009
Margin increased by $37.0 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $30.7 million due to an increase in base rates approved by the SCPSC under the BLRA. In addition, margin increased by $54.2 million (net of eWNA after its implementation) due to weather, by $5.8 million due to higher transmission revenue and off-system sales and by $13.6 million due to the adoption of SCPSC-approved lower electric depreciation rates in 2009, the effect of which was offset by a reduction in the recovery of fuel costs (electric revenue). During the first quarter of 2010, the Company deferred $25 million of incremental revenue as a result of the abnormally cold weather in SCE&G’s service territory (see Note 2 to the consolidated financial statements). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding. (See also discussion at “Income Taxes”.) Finally, pursuant to the SCPSC-approved retail electric base rate order in 2010, SCE&G adopted an eWNA thereby mitigating the effects of abnormal weather on its margins.
Sales volumes (in GWh) related to the electric margin above, by class, were as follows:
·
2011 vs 2010
Total retail sales volumes decreased by 775 GWh due to weather.
·
2010 vs 2009
Total retail sales volumes increased by 1,209 GWh due to weather and by 539 GWh due to higher industrial sales volumes.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy. Gas Distribution sales margin (including transactions with affiliates) was as follows:
·
2011 vs 2010
Margin at SCE&G decreased by $8.2 million due to the SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. This decrease was partially offset by an increase of $1.8 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2011. Margin at PSNC Energy increased $2.9 million due to residential and commercial customer growth.
·
2010 vs 2009
Margin at SCE&G increased by $9.2 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009 and $3.3 million due to increased customer usage. These increases were partially offset by a decrease of $2.2 million due to an SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. Margin at PSNC Energy increased by $4.0 million primarily due to residential customer growth and improved industrial usage.
Sales volumes (in DT) by class, including transportation gas, were as follows:
·
2011 vs 2010
Residential, commercial and industrial sales volume decreased primarily due to milder weather. Transportation sales volume increased primarily as a result of improved economic conditions and the competitive price of gas versus alternate fuel sources.
·
2010 vs 2009
Residential sales volume increased primarily due to customer growth and weather. Commercial and industrial sales volume increased primarily as a result of improved economic conditions.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy which operates in Georgia’s natural gas market. Retail Gas Marketing revenues and income available to common shareholders were as follows:
·
2011 vs 2010
Operating revenues decreased as a result of milder weather and lower consumption. Income available to common shareholders decreased due to lower margins, partially offset by lower bad debt and operating expenses.
·
2010 vs 2009
Operating revenues increased as a result of colder than normal weather and higher consumption. Income available to common shareholders increased due to higher margins, partially offset by higher bad debt and operating expenses.
Energy Marketing
Energy Marketing is comprised of the Company’s nonregulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and income available to common shareholders were as follows:
·
2011 vs 2010
Operating revenues decreased due to lower market prices. Income available to common shareholders increased due to lower operating expenses, including bad debt.
·
2010 vs 2009
Operating revenues increased due to higher sales volume. Income available to common shareholders increased due to lower operating expenses, partially offset by higher bad debt expense.
Other Operating Expenses
Other operating expenses were as follows:
·
2011 vs 2010
Other operation and maintenance expenses decreased by $7.8 million due to lower customer service expenses, including bad debt expense, and by $4.1 million due to lower incentive compensation and other benefits. These decreases were partially offset by $0.8 million due to higher generation, transmission and distribution expenses. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.
·
2010 vs 2009
Other operation and maintenance expenses increased by $17.7 million due to higher generation, transmission and distribution expenses, by $10.9 million due to higher incentive compensation and other benefits and by $6.1 million due to higher customer service expenses and general expenses, including bad debt expense. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.
Other Income (Expense)
Other income (expense) includes the results of certain incidental (non-utility) activities and the activities of certain non-regulated subsidiaries. Components of other income (expense) were as follows:
·
2011 vs 2010
Changes in other income (expense) were not significant.
·
2010 vs 2009
Total other income (expense) decreased $13.4 million due to decreased interest income. In September 2009, as a result of a favorable decision by the South Carolina Supreme Court, SCE&G was refunded previously contested EIZ Credits of $15.3 million and an additional $14.3 million of interest income. SCE&G recorded a multi-year catch-up adjustment in the third quarter of 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes. The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.
Interest Expense
Components of interest expense, net of the debt component of AFC, were as follows:
Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year. Other interest expense increased in 2011, and decreased in 2010, primarily due to corresponding changes in principal balances outstanding on short-term debt over the respective prior year.
Income Taxes
Income tax expense (and the effective tax rate) increased in 2011 over 2010 primarily due to the accelerated amortization of deferred EIZ Credits to offset undercollected fuel costs in 2010 pursuant to an SCPSC order and an increase in operating income. Income tax expense (and the effective tax rate) decreased in 2010 over 2009 primarily due to the above-mentioned accelerated amortization of EIZ Credits to offset undercollected fuel costs and the accelerated amortization of EIZ Credits in connection with the July 2010 retail electric rate order. (See Note 5 to the consolidated financial statements for reconciling differences between income tax expense and statutory tax expense.)
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, 2011 was 2.87.
Cash requirements for SCANA’s regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.
The Company also obtains equity from SCANA’s stock plans. Shares of SCANA common stock are acquired on behalf of participants in SCANA’s Investor Plus Plan and Stock Purchase-Savings Plan through the original issuance of shares, rather than being purchased on the open market. This provided approximately $97 million of additional equity during 2011 and is expected to provide approximately $102 million of additional capital in 2012. Due primarily to new nuclear construction plans, the Company anticipates keeping this strategy in place for the foreseeable future. The Company also expects to issue common stock in 2012 under forward contracts executed in 2010 (and extended by amendment in October 2011).
SCANA’s leverage ratio of long- and short-term debt to capital was approximately 58% at December 31, 2011. SCANA has publicly announced its desire to maintain its leverage ratio at levels between 54% and 57%, but SCANA’s ability to achieve and maintain those levels depends on a number of factors. In the future, if SCANA is not able to achieve and maintain its leverage ratio within the desired range, the Company’s debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.
Capital Expenditures
Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC, were $884 million in 2011 and are estimated to be $1.4 billion in 2012.
The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2012-2014, which are subject to continuing review and adjustment, are as follows:
Estimated Capital Expenditures
The Company’s contractual cash obligations as of December 31, 2011 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 the New Units at the Summer Station site. SCE&G expects to be a joint owner and share operating costs and generation output of the New Units, with SCE&G accounting for 55 percent of the cost and output and the other joint owner(s) the remaining 45 percent. 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, 2011, obligations arising from these contracts are included in the purchase obligations within the Contractual Cash Obligations table above.
Also included in purchase obligations are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such arrangements without penalty.
Other commercial commitments includes estimated obligations under forward contracts for natural gas purchases. Forward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. Other commercial commitments also includes a “take-and-pay” contract for natural gas which expires in 2019 and estimated obligations for coal and nuclear fuel purchases. In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no significant contributions are anticipated until after 2012. Cash payments under the health care and life insurance benefit plan were $12.2 million in 2011, and such annual payments are expected to be the same or increase up to $14.0 million in the future.
In addition, the Company is party to certain NYMEX futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for purposes other than trading.
Interest Rate Risk
The tables below provides information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average interest rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.
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 $15 million at December 31, 2011 and $21 million at December 31, 2010, which amounts do not have a stated interest rate associated with them.
For further discussion of the Company’s long-term debt and interest rate derivatives, see ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES and also Notes 4 and 6 of the condensed consolidated financial statements.
Commodity Price Risk
The following tables provide information about the Company’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value represents quoted market prices.
Expected Maturity:
(a) Weighted average, in dollars
(b) Millions of dollars
(a) Weighted average, in dollars
(b) Millions of dollars
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 to the consolidated financial statements. The information above includes those financial positions of Energy Marketing, SCE&G and PSNC Energy.
SCE&G and PSNC Energy utilize futures, options and swaps to hedge gas purchasing activities. SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCE&G’s hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through weighted average cost of gas calculations. The offset to the change in fair value of these derivatives is deferred. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy defers premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program for subsequent recovery from customers.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
SCANA Corporation
Cayce, South Carolina
We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in common equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 29, 2012, expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 29, 2012
SCANA Corporation
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND
COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Principles of Consolidation
SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company also conducts other energy-related business and provides fiber optic communications in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and two other wholly-owned subsidiaries liquidated in 2011.
The Company reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable as permitted by accounting guidance.
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.
Utility Plant
Utility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 4.7% for 2011, 7.4% for 2010 and 7.5% for 2009. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.
The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows:
SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.
Jointly Owned Utility Plant
SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses are included in the corresponding operating expenses on its income statement.
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $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.
SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent of the output of the New Units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.
The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site. These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium. While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million. SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (see Note 2 to the consolidated financial statements), will be recoverable through rates.
Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6 million at December 31, 2011 and $77.9 million at December 31, 2010.
Major Maintenance
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the year ended December 31, 2011, SCE&G incurred $11.5 million for turbine maintenance. Cumulative
costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage. SCE&G accrued $1.2 million per month from July 2008 through July 2011 for its portion of the outages in the fall of 2009 and the spring of 2011. Total costs for the 2009 outage were $32.7 million, of which SCE&G was responsible for $21.8 million. Total costs for the 2011 outage were $34.1 million, of which SCE&G was responsible for $22.7 million. In July 2011, SCE&G began accruing $1.2 million per month for its portion of the refueling planned for the fall of 2012. SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.
Goodwill
The Company considers amounts categorized by FERC as “acquisition adjustments” with carrying values of $210 million for PSNC Energy (Gas Distribution segment) and $20 million for CGT (All Other segment) to be goodwill. The Company tests these goodwill amounts for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is a two-step process which in step one requires estimation of the fair value of the respective reporting unit and the comparison of that amount to the carrying value of the reporting unit. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. In the first quarter of 2012, the Company will adopt accounting guidance whereby it will have the option to first perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company will not be required to proceed with the two-step quantitative assessment.
In evaluations of PSNC Energy, fair value is estimated using the assistance of an independent appraisal. In evaluations of CGT, estimated fair value has been obtained from internal analyses. In all evaluations for the periods presented, step one has indicated no impairment, and no impairment charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense.
Nuclear Decommissioning
SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2011, 2010 and 2009) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.
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.
Account Receivable
Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.
Asset Management and Supply Service Agreements
PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At December 31, 2011, such counterparties held 45% of PSNC Energy’s natural gas inventory, with a carrying value of $28.7 million, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire at various times through March 31, 2013.
Income Taxes
The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense.
Regulatory Assets and Regulatory Liabilities
The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.
Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
The Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.
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. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debits and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.
Income Statement Presentation
In its consolidated statements of income, the Company presents the activities of its regulated and significant nonregulated businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).
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 $169.1 million at December 31, 2011 and $221.1 million at December 31, 2010.
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual hearing.
SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs, including the results of its hedging program, and amounts contained in rates is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers, and it will continue on a pilot basis unless modified or terminated by the SCPSC.
PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average, per customer consumption, whether impacted by weather or other factors.
Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Accordingly, no such taxes are included in revenues or expenses in the statements of income.
Earnings Per Share
The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has issued no securities that would have an antidilutive effect on earnings per share.
A reconciliation of the weighted average number of common shares for each of the three years ended December 31, 2011 for basic and diluted purposes is as follows:
New Accounting Matters
Effective for the first quarter of 2012, the Company will adopt accounting guidance that revises how comprehensive income is presented in its financial statements. The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.
Effective for the first quarter of 2012, the Company will adopt accounting guidance that permits it to make a qualitative assessment about the likelihood of goodwill impairment each year. The results of such an assessment may lead the Company to determine that performing a two-step quantitative impairment test is unnecessary. The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.
2. RATE AND OTHER REGULATORY MATTERS
Rate Matters
Electric
SCE&G’s retail electric rates are established in part by using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs. In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011. SCE&G was allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period. In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011. On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. In February 2012, SCE&G requested authorization to decrease the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2012. The next annual hearing to review base rates for fuel costs is scheduled for March 22, 2012.
On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. Among other things, the SCPSC’s order (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.
On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs. By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition. The increase became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC its annual update on DSM programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net revenue, and the approved shared savings incentive for investing in such DSM Programs.
Electric - BLRA
In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of 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.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.
In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflected the removal of the contingency reserve and incorporated then identifiable capital costs of $173.9 million (in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.
On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed in Note 1 to the consolidated financial statements (e.g., those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site).
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:
Gas
SCE&G
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the billing cycle of November in the following years:
SCE&G’s natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.
PSNC Energy
PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost. The Rider D rate mechanism also allows it to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.
PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.
In January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in February 2012.
In December 2011, in connection with PSNC Energy’s 2011 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2011. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will have a material effect on the Company’s results of operations, cash flows, or financial condition.
In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2011. In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.
Regulatory Assets and Regulatory Liabilities
The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and liabilities which are summarized in the following tables. Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections-electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods. These amounts are expected to be recovered in retail electric rates during the period January 2013 through April 2013. SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.
Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assets are expected to be recovered over periods of up to approximately 23 years.
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 95 years.
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become longer at the election of the SCPSC.
Planned major maintenance related to certain fossil fuel turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.
Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate swaps designated as cash flow hedges. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.4 million at December 31, 2011 and are being recovered through utility rates over approximately 30 years. The remaining costs relate to Wateree Station, for which the Company will seek recovery in future proceedings before the SCPSC. SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.
Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.
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 and vegetation management expenditures in excess of amounts included in base rates. During the years ended December 31, 2011 and 2010, SCE&G applied costs of $6.4 million and $9.5 million, respectively, to the reserve. Pursuant to SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely pending future SCPSC action.
The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be amortized into operating revenue through February 2024.
The SCPSC, the NCUC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, 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. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.
3. COMMON EQUITY
The Company’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCANA’s junior subordinated indenture (relating to the Hybrids), SCE&G’s bond indenture (relating to the Bonds) and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on their respective common stock.
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2011, approximately $58.8 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.
Cash dividends on SCANA’s common stock were declared during 2011, 2010 and 2009 at an annual rate per share of $1.94, $1.90 and $1.88, respectively.
The accumulated balances related to each component of other comprehensive income (loss) were as follows:
The Company recognized losses of $7.0 million, $12.3 million and $66.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2011, 2010 and 2009, respectively.
Authorized shares of common stock were 200 million as of December 31, 2011 and 150 million as of December 31, 2010.
SCANA issued common stock valued at $97.8 million, $91.1 million and $91.1 million (when issued) during the years ended December 31, 2011, 2010 and 2009, respectively, which was satisfied using original issue shares, through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan.
SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010 and entered into forward agreements for the sale of approximately 6.6 million shares. The forward agreements, after being extended by amendment dated October 26, 2011, are to be settled no later than December 31, 2012. SCANA intends to use the net proceeds to finance capital expenditures, including the construction of the New Units, and for general corporate purposes, including repayment of indebtedness incurred for such purposes.
On January 7, 2009, SCANA issued common stock valued at $102.1 million (at time of issue). Net proceeds were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.
4. LONG-TERM AND SHORT-TERM DEBT
Long-term debt by type with related weighted average interest rates and maturities at December 31 is as follows:
(a) Includes fixed rate debt hedged by variable interest rate swaps of $250 million in 2011 and $550 million in 2010.
(b) Variable rate notes hedged by a fixed interest rate swap.
(c) May be extended through 2080.
(d) Includes variable rate debt hedged by fixed rate swaps of $71.4 million in 2011 and 2010.
(e) Includes fixed rate debt hedged by a variable interest rate swap of $3.2 million in 2011 and $6.4 million in 2010.
The annual amounts of long-term debt maturities for the years 2012 through 2016 are summarized as follows:
In January 2012, SCANA issued $250 million of 4.125% medium term notes due February 1, 2022. Proceeds from the sale were used to retire SCANA’s $250 million of 6.25% medium term notes due February 1, 2012. The borrowings refinanced by this 2012 issuance are classified within Long-term Debt, Net in the consolidated balance sheet.
In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.
Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.
Lines of Credit and Short-Term Borrowings
At December 31, 2011 and 2010, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.1 billion (of which $400 million relates to Fuel Company), and $100 million, respectively, which expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCANA, SCE&G (including Fuel Company) and PSNC Energy.
The Company is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company. The letters of credit expire, subject to renewal, in the fourth quarter of 2014.
The Company pays fees to banks as compensation for maintaining committed lines of credit.
5. INCOME TAXES
Total income tax expense attributable to income for 2011, 2010 and 2009 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 $1.5 billion at December 31, 2011 and $1.4 billion at December 31, 2010 are as follows:
The Company files a consolidated federal income tax return, and the Company and its subsidiaries file various applicable state and local income tax returns. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 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 2008.
In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, the Company revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.
Changes to Unrecognized Tax Benefits
In connection with the change in method of accounting for certain repair costs for tax purposes referred to above, the Company identified approximately $38 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. By December 31, 2012, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $38 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.
The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2010 or 2009. The Company has accrued $2 million of interest expense related to unrecognized tax benefits in 2011.
6. 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 as a component of other comprehensive income (loss) or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Company’s Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
Commodity Derivatives
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions. Cash settlement of commodity derivatives are classified as an operating activity in the consolidated statement of cash flows.
The Company’s regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCE&G’s hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or
losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.
The unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in other comprehensive income. When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from other comprehensive income to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.
As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives.
Interest Rate Swaps
The Company uses interest rate swaps to manage interest rate risk and exposure to changes in the fair value attributable to changes in interest rate on certain debt issuances. These swaps are designated as either fair value hedges or cash flow hedges.
The Company uses swaps to synthetically convert fixed rate debt to variable rate debt. These swaps are designated as fair value hedges. Periodic payments to or receipts from swap counterparties are recorded within interest expense and are classified as an operating activity in the condensed consolidated statements of cash flows. In addition, gains on certain swaps that were terminated prior to maturity of the underlying debt instruments are being amortized to interest expense over the life of the debt they hedged.
The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.
In anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges. The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities, and for the holding company or nonregulated subsidiaries, are recorded in other comprehensive income. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions are recognized in income. Cash payments made or received upon termination of these financial instruments are classified as an investing activity in the consolidated statements of cash flows.
Quantitative Disclosures Related to Derivatives
The Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes an aggregate 9,626,000 DT related to basis swap contracts in Energy Marketing.
(b) Includes an aggregate 6,485,536 DT related to basis swap contracts in Retail Gas Marketing and Energy Marketing.
The Company was party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $253.2 million and $556.4 million at December 31, 2011 and 2010, respectively, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $822.6 million and $1.1 billion, respectively.
The fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheet as follows:
(c) 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 on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.
The effect of derivative instruments on the statement of income is as follows:
With regard to the Company’s interest rate swaps designated as fair value hedges, the gains on those swaps and the losses on the hedged fixed rate debt are recognized in current earnings and included in interest expense. These gains and losses, combined with the amortization of deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $5.8 million and $11.5 million for the years ended December 31, 2011 and 2010, respectively.
Derivatives in Cash Flow Hedging Relationships
As of December 31, 2011, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $6.7 million, net of tax as an increase to gas cost and approximately $4.3 million, net of tax as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2011, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2016.
Hedge Ineffectiveness
Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were $(1.1) million, net of tax, in 2011 and were insignificant in 2010. 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, 2011 and 2010, the Company has posted $140.3 million and $20.0 million, respectively, of collateral related to derivatives with contingent provisions that are in a net liability position. If all of the contingent features underlying these instruments were fully triggered as of December 31, 2011 and 2010, the Company would be required to post an additional $50.7 million and $74.0 million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2011 and 2010, are $191.0 million and $94.0 million, respectively.
7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition, there were no transfers of fair value amounts into or out of Levels 1 and 2 during any period presented.
Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2011 and December 31, 2010 were as follows:
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on discounted cash flow models with independently sourced data. Early settlement of long-term debt may not be possible or may not be considered prudent.
8. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefit Plans
The Company sponsors a noncontributory defined benefit pension plan covering substantially all regular, full-time employees. The Company’s policy has been to fund the plan to the extent permitted by applicable federal income tax regulations, as determined by an independent actuary.
The Company’s pension plan provides benefits under 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. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment.
In addition to pension benefits, the Company provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.
Changes in Benefit Obligations
The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for retirement benefits and the accumulated benefit obligation for other postretirement benefits are presented below.
The accumulated benefit obligation for retirement benefits was $784.9 million at the end of 2011 and $766.0 million at the end of 2010. The accumulated retirement benefit obligation differs from the projected retirement benefit obligation above in that it reflects no assumptions about future compensation levels.
Significant assumptions used to determine the above benefit obligations are as follows:
An 8.2% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease gradually to 5.0% for 2020 and to remain at that level thereafter.
A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at December 31, 2011 by $1.7 million and at December 31, 2010 by $1.8 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 2011 by $1.5 million and at December 31, 2010 by $1.6 million.
Funded Status
Amounts recognized on the consolidated balance sheets consist of:
Amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2011 and 2010 were as follows:
In connection with the joint ownership of Summer Station, as of December 31, 2011 and 2010, the Company recorded within deferred debits $19.7 million and $13.0 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2011 and 2010, the Company also recorded within deferred debits $11.4 million and $10.7 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.
Changes in Fair Value of Plan Assets
Investment Policies and Strategies
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability for the pension plan, (2) maximizing return within reasonable and prudent levels of risk in order to minimize contributions, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, investment managers and performance expectations. Transactions involving certain types of investments are prohibited. Equity securities held by the pension plan during the periods presented did not include SCANA common stock.
The Company’s pension plan asset allocation at December 31, 2011 and 2010 and the target allocation for 2012 are as follows:
For 2012, the expected long-term rate of return on assets will be 8.25%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, and assumes an asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.
Fair Value Measurements
Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2011 and 2010, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
The Pension Plan values common stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds, common collective trusts and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. Government agency securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments. Hedge funds are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The valuation of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur.
Expected Cash Flows
The total benefits expected to be paid from the pension plan or from the Company’s assets for the other postretirement benefits plan, respectively, are as follows:
Expected Benefit Payments
* Net of participant contributions
Pension Plan Contributions
The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and the Company does not anticipate making significant contributions to the pension plan until after 2012.
Net Periodic Benefit Cost (Income)
The Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.
Components of Net Periodic Benefit Cost
In February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of increased pension cost by deferring as a regulatory asset the amount of pension cost above that which was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.
Other changes in plan assets and benefit obligations recognized in other comprehensive income were as follows:
Significant Assumptions Used in Determining Net Periodic Benefit Cost
The estimated amounts to be amortized from accumulated other comprehensive income into net periodic benefit cost in 2012 are as follows:
Other postretirement benefit costs are subject to annual per capita limits pursuant to plan design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is approximately $100,000.
Stock Purchase Savings Plan
The Company also sponsors a defined contribution plan in which eligible employees may participate. Eligible employees may defer up to 25% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan for 2011, 2010 and 2009 were $21.8 million, $20.8 million and $21.0 million, respectively, and were made in the form of SCANA common stock.
9. SHARE-BASED COMPENSATION
The Plan provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The Plan currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.
Compensation costs related to share-based payment transactions are required to be recognized in the financial statements. With limited exceptions, including those liability awards discussed below, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award.
Liability Awards
The 2009-2011, 2010-2012, and 2011-2013 performance cycles provide for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle. In each of the performance cycles, 20% of the performance award was granted in the form of restricted share units, which are liability awards payable in cash and are subject to forfeiture in the event of retirement or termination of employment prior to the end of the cycle, subject to exceptions for death, disability or change in control. The remaining 80% of the award was made in performance shares. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on the performance shares. Payout of performance share awards was determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%). Payouts under the 2009-2011 performance cycle were earned for each year that performance goals were met during the three-year cycle. Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2012.
Compensation cost of all these liability awards is recognized over their respective three-year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities related to similar prior programs were paid totaling $13.6 million in 2011, $12.1 million in 2010, and $9.1 million in 2009.
Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $6.1 million in 2011, $14.2 million in 2010 and $7.2 million in 2009. Fair value adjustments resulted in capitalized compensation costs of $0.9 million in 2011, $2.4 million in 2010 and $0.9 million in 2009.
Equity Awards
In the 2008-2010 performance cycle, 20% of the performance award was granted in the form of restricted (nonvested) shares rather than restricted share units. A summary of activity related to these 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. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized. The Company expensed compensation costs for nonvested shares of $0.7 million in each of 2010 and 2009 and recognized related tax benefits of $0.3 million in each of 2010 and 2009. The Company capitalized compensation costs of $0.1 million in each of 2010 and 2009.
A summary of activity related to nonqualified stock options follows:
No stock options were granted or forfeited and all options were fully vested during the periods presented. The options expire ten years after their respective grant dates, and all options currently outstanding will expire in 2012. At December 31, 2011, all outstanding options were currently exercisable at a price of $27.52, and had a weighted-average remaining contractual life of less than one year.
The exercise of stock options during the periods presented were satisfied using original issue shares. For the years ended December 31, 2011, 2010 and 2009, cash realized upon the exercise of options and related tax benefits were not significant.
10. COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the company’s nuclear power plant. Price-Anderson provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.
SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to the nuclear facility for property damage and outage costs up to $2.75 billion. In addition, a builder’s risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the Owners up to $500 million in limits of accidental property damage occurring during construction. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premiums, SCE&G’s portion of the prospective premium assessment would not exceed $37.3 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s results of operations, cash flows and financial position.
Environmental
SCE&G
In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the CAIR, which required 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. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with the CSAPR and the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.
SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and expects to recover them through rates.
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2014 and will cost an additional $8.3 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements. At December 31, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9 million and are included in regulatory assets.
PSNC Energy
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $3.1 million, the estimated remaining liability at December 31, 2011. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.
Claims and Litigation
In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. This settlement did not have a material impact on the Company’s results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on the Company’s results of operations, cash flows or financial condition.
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 2057. Rent expense totaled approximately $15.8 million in 2011, $13.9 million in 2010 and $23.7 million in 2009. Future minimum rental payments under such leases are as follows:
Purchase Commitments
The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, nuclear fuel contracts, construction projects and other commitments totaled $1.7 billion in 2011, $1.9 billion in 2010 and $1.7 billion in 2009. Future payments under such purchase commitments are as follows:
Forward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts.
Guarantees
The Company issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues. The Company is not required to recognize a liability for guarantees issued on behalf of its subsidiaries unless it becomes probable that performance under the guarantees will be required. The Company believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2011, the maximum future payments (undiscounted) that the Company could be required to make under guarantees totaled $1.5 billion.
Asset Retirement Obligations
The Company recognizes a liability for the fair value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
The legal obligations associated with the retirement of long-lived tangible assets that results from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations. As of December 31, 2011, the Company has recorded an ARO of approximately $124 million for nuclear plant decommissioning (see Note 1) and an ARO of approximately $349 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:
11. AFFILIATED TRANSACTIONS
The Company received cash distributions from equity-method investees of $5.5 million in 2011, $4.8 million in 2010 and $3.3 million in 2009. The Company made investments in equity-method investees of $13.6 million in 2011, $5.1 million in 2010 and $1.6 million in 2009.
SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, both involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G’s receivables from these affiliates were $8.5 million at December 31, 2011 and insignificant at December 31, 2010. SCE&G’s payables to these affiliates were $8.6 million at December 31, 2011 and insignificant at December 31, 2010. SCE&G accounts for these investments using the equity method. SCE&G’s total purchases were $123.8 million in 2011 and $97.3 million in 2010. SCE&G’s total sales were $123.3 million in 2011 and $96.9 million in 2010.
12. SEGMENT OF BUSINESS INFORMATION
The Company’s reportable segments are described below. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations is primarily engaged in the generation, transmission and distribution of electricity, and is regulated by the SCPSC and FERC.
Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, is engaged in the purchase and sale, primarily at retail, of natural gas. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively.
Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the GPSC. Energy Marketing markets natural gas to industrial and large commercial customers and municipalities, primarily in the Southeast.
All Other is comprised of other direct and indirect wholly-owned subsidiaries of the Company. One of these subsidiaries operates a FERC-regulated interstate pipeline company and the other subsidiaries conduct nonregulated operations in energy-related and telecommunications industries. None of these subsidiaries met the quantitative thresholds for determining reportable segments during any period reported.
The Company’s regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. The marketing segments differ from each other in their respective markets and customer type.
Disclosure of Reportable Segments (Millions of dollars)
Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, SCE&G does not allocate interest charges, income tax expense or assets other than utility plant to its segments. For nonregulated operations, management uses income available to common shareholders as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. The Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.
The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to Income Available to Common Shareholders consist of SCE&G’s unallocated income available to common shareholders of SCANA Corporation.
Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.
Adjustments to Interest Expense, Income Tax Expense, Expenditures for Assets and Deferred Tax Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to asset retirement obligations. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Page
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Results of Operations
Liquidity and Capital Resources
Environmental Matters
Regulatory Matters
Critical Accounting Policies and Estimates
Other Matters
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Equity and Comprehensive Income
Notes to Consolidated Financial Statements
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
SCE&G is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, and transportation of natural gas. SCE&G’s business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 22,600 square miles.
Key Earnings Drivers and Outlook
During 2011, economic growth showed modest signs of improvement in the southeast. Significant industrial announcements in SCE&G’s service territory were made during the year. In addition, SCE&G’s residential and commercial customer growth rates were positive, though customer usage by existing customers continued to decline. At December 31, 2011, a preliminary estimate of seasonally adjusted unemployment for South Carolina was 9.5%. Though improved from the 10.9% unemployment rate at December 31, 2010, unemployment remains high and continues to slow the pace of economic recovery in South Carolina.
Over the next five years, key earnings drivers for SCE&G will be additions to utility rate base, consisting primarily of capital expenditures for new generating capacity, environmental facilities and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage 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, GENCO and Fuel Company, and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 2011 SCE&G provided electricity to approximately 664,000 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, certain fossil fuels and emission allowances.
Operating results for electric operations are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity is 10.7% for non-BLRA expenditures, and 11.0% for BLRA-related expenditures. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.
New Nuclear Construction
SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two 1,117-MW nuclear generation units to be constructed at the site of Summer Station, 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. Under these agreements, SCE&G will have the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online.
SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction of the New Units. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. The successful completion of the New Units would result in a substantial increase in SCE&G’s utility plant in service. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to SCE&G.
As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units.
The Consortium has recently performed an impact study, at SCE&G’s request, related to various cost and timing alternatives arising from the delay in the issuance date of the COL from mid-2011, which was the date assumed when the EPC Contract was signed in 2008, to the early-2012 issuance date currently anticipated by SCE&G. SCE&G has recently informed the Consortium that it intends to pursue the alternative that would delay the substantial completion date of the first New Unit and accelerate the substantial completion date for the second New Unit and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.
In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactor to be used for the New Units. This certification is a necessary step before the NRC can issue a COL for the New Units. In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.
See additional discussion at OTHER MATTERS - Nuclear Generation.
Environmental
Significant federal legislative initiatives related to energy were unsuccessful in 2011, and Consolidated SCE&G expects such legislative initiatives will be hampered through 2012, due to each chamber of Congress being controlled by different political parties. The EPA, however, did issue new rules in 2011 related to air quality, including CSAPR and MATS, which require reductions in power plant emissions of sulfur dioxide, nitrogen oxide and mercury, among other substances. Though implementation of CSAPR was stayed by the United States Court of Appeals for the District of Columbia pending judicial review, Consolidated SCE&G cannot predict the outcome that judicial review will have on the rule’s implementation. In 2012, additional significant regulatory initiatives by the EPA and other federal agencies will likely proceed. These initiatives may require Consolidated SCE&G to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. Consolidated SCE&G cannot predict whether such initiatives will be enacted, and if they are, the conditions they would impose on utilities.
The EPA has stated its intention to propose, in late 2012, new federal regulations affecting the management and disposal of CCR, such as ash. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. The EPA is also expected to issue regulations during 2012 for cooling water intake structures to meet BACT at existing power generating stations. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.
Gas Distribution
The Gas Distribution segment, comprised of the local distribution operations of SCE&G, is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of South Carolina. At December 31, 2011 this segment provided natural gas to approximately 317,000 customers in areas covering 22,600 square miles.
Operating results for gas distribution are primarily influenced by customer demand for natural gas rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity.
Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact SCE&G’s ability to
retain large commercial and industrial customers. One effect of the sluggish economy has been an overall decrease in demand for natural gas which, coupled with discoveries of shale gas in the United States, resulted in significantly lower prices for this commodity in 2010 and 2011. Low natural gas commodity prices are expected to continue in 2012 and beyond.
RESULTS OF OPERATIONS
Net Income
Net income for Consolidated SCE&G was as follows:
·
2011 vs 2010
Net income increased $46.7 million due to higher electric margin and by $1.0 million due to lower operation and maintenance expenses. This increase was partially offset by $4.1 million due to lower gas margin, higher depreciation expense of $9.1 million, higher property taxes of $6.2 million, higher interest expense of $11.0 million and lower AFC of $5.8 million.
·
2010 vs 2009
Net income increased $72.7 million due to higher electric margin and $6.5 million due to higher gas margin. These increases were partially offset by increased generation, transmission and distribution expenses of $10.4 million, by increased incentive compensation of $5.6 million, by increased interest expense of $14.2 million, by lower equity AFC of $8.8 million, by higher property taxes of $7.5 million and by $12.9 million due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in 2009. In late 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.
Pension Cost
Pension cost was recorded on Consolidated SCE&G’s income statements and balance sheets as follows:
Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension cost related to retail electric and gas operations that otherwise would have been charged to expense. These costs will be deferred until such time as future rate recovery is provided for by the SCPSC.
No contribution to the pension trust was necessary, nor did limitations on benefit payments apply, in or for any period reported.
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. Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 4.5% of income before income taxes in 2011, 6.6% in 2010 and 11.5% in 2009, respectively.
Dividends Declared
Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2011 and 2010:
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows:
·
2011 vs 2010
Margin increased by $49.0 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA and by $34.5 million due to an SCPSC-approved increase in retail electric base rates in July 2010. Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order in connection with SCE&G’s annual fuel cost proceeding. These increases were partially offset by $12 million due to the effects of weather in 2010 before the implementation of the SCPSC-approved eWNA and by lower customer usage of $8.7 million.
·
2010 vs 2009
Margin increased by $37.0 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $30.7 million due to an increase in base rates approved by the SCPSC under the BLRA. In addition, margin increased by $54.2 million (net of eWNA after its implementation) due to weather, by $5.8 million due to higher transmission revenue and off-system sales and by $13.6 million due to the adoption of SCPSC-approved lower electric depreciation rates in 2009, the effect of which was offset by a reduction in the recovery of fuel costs (electric revenue). During the first quarter of 2010, SCE&G deferred $25 million of incremental revenue as a result of the abnormally cold weather in its service territory (see Note 2 to the consolidated financial statements). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding. (See also discussion at “Income Taxes”.) Finally, pursuant to the SCPSC-approved retail electric base rate order in 2010, SCE&G adopted an eWNA thereby mitigating the effects of abnormal weather on its margins.
Sales volumes (in GWh) related to the electric margin above, by class, were as follows:
·
2011 vs 2010
Total retail sales volumes decreased by 775 GWh due to weather.
·
2010 vs 2009
Total retail sales volumes increased by 1,209 GWh due to weather and by 539 GWh due to higher industrial sales volumes.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margin (including transactions with affiliates) was as follows:
·
2011 vs 2010
Margin decreased $8.2 million due to the SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. This decrease was partially offset by an increase of $1.8 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2011.
·
2010 vs 2009
Margin increased $9.2 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009 and $3.3 million due to increased customer usage. These increases were partially offset by a decrease of $2.2 million due to a SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010.
Sales volumes (in DT) by class, including transportation gas, were as follows:
·
2011 vs 2010
Residential and commercial sales decreased primarily due to milder weather. Industrial and transportation sales increased primarily as a result of improved economic conditions and the competitive price of gas versus alternate fuel sources.
·
2010 vs 2009
Residential sales volume increased primarily due to customer growth and weather. Commercial and industrial sales volume increased primarily as a result of improved economic conditions.
Other Operating Expenses
Other operating expenses were as follows:
·
2011 vs 2010
Other operation and maintenance expenses increased primarily due to higher generation, transmission and distribution expenses. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.
·
2010 vs 2009
Other operation and maintenance expenses increased by $16.9 million due to higher generation, transmission and distribution expenses and by $9.0 million due to higher incentive compensation and other benefits. Depreciation and amortization expense increased primarily due to 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:
* Greater than 100%
·
2011 vs 2010
Total other income (expense) decreased primarily due to lower pension income in 2011.
·
2010 vs 2009
Total other income (expense) decreased $16.0 million due to decreased interest income. In September 2009, as a result of a favorable decision by the South Carolina Supreme Court, SCE&G was refunded previously contested EIZ Credits of $15.3 million and an additional $14.3 million of interest income. SCE&G recorded a multi-year catch-up adjustment in the third quarter of 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes. The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.
Interest Expense
Components of interest expense, net of the debt component of AFC, were as follows:
Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year. Other interest expense increased in each year primarily due to higher principal balances on short-term debt over the prior year.
Income Taxes
Income tax expense (and the effective tax rate) increased in 2011 over 2010 primarily due to the accelerated amortization of deferred EIZ Credits to offset undercollected fuel costs in 2010 pursuant to an SCPSC order and an increase in operating income. Income tax expense (and the effective tax rate) decreased in 2010 over 2009 primarily due to the above-mentioned accelerated amortization of EIZ Credits to offset undercollected fuel costs and the accelerated amortization of EIZ Credits in connection with the July 2010 retail electric rate order. (See Note 5 to the consolidated financial statements for reconciling differences between income tax expense and statutory tax expense.)
LIQUIDITY AND CAPITAL RESOURCES
Consolidated SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short- and long-term indebtedness and capital contributions from SCANA. Consolidated SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. Consolidated SCE&G’s ratio of earnings to fixed charges for the year ended December 31, 2011 was 3.13.
Consolidated SCE&G’s cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of Consolidated SCE&G to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental
regulations, will depend upon its ability to attract the necessary financial capital on reasonable terms. Consolidated SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and Consolidated SCE&G continues its ongoing construction program, Consolidated SCE&G expects to seek increases in rates. Consolidated SCE&G’s future financial position and results of operations will be affected by Consolidated SCE&G’s ability to obtain adequate and timely rate and other regulatory relief.
Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $786 million in 2011 and are estimated to be $1.3 billion in 2012.
Consolidated SCE&G’s current estimates of its capital expenditures for construction and nuclear fuel for 2012-2014, which are subject to continuing review and adjustment, are as follows:
Estimated Capital Expenditures
Consolidated SCE&G’s contractual cash obligations as of December 31, 2011 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 the New Units at the Summer Station site. SCE&G expects to be a joint owner and share operating costs and generation output of the New Units, with SCE&G accounting for 55 percent of the cost and output and other joint owner(s) the remaining 45 percent. 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, 2011, 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. SCE&G also has a legal obligation associated with the decommissioning and dismantling of Summer Station Unit 1 and other conditional asset retirement obligations that are not listed in the contractual cash obligations above. See Notes 1 and 10 to the consolidated financial statements.
In addition, Consolidated SCE&G is party to certain NYMEX futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
At December 31, 2011, Consolidated SCE&G had posted $45 million in cash collateral for interest rate derivative contracts.
Financing Limits and Related Matters
Consolidated SCE&G’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including the SCPSC and FERC. Financing programs currently utilized by Consolidated SCE&G are as follows.
SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes or commercial paper with maturity dates of one year or less, and GENCO may issue up to $150 million of short-term indebtedness. The authority to make such issuances will expire in October 2012.
SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company, which expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by 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).
At December 31, 2011 and 2010, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
As of December 31, 2011, Consolidated SCE&G had no outstanding borrowings under its $1.1 billion facilities, had approximately $512 million in commercial paper borrowings outstanding, was obligated under $.3 million in LOC-supported letters of credit, and had approximately $16 million in cash and temporary investments. Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance
on its draws, while maintaining appropriate levels of liquidity. Average short-term borrowings outstanding during 2011 were approximately $485 million. Short-term cash needs were met primarily through the issuance of commercial paper.
At December 31, 2011, Consolidated SCE&G had net available liquidity of approximately $604 million, and its revolving credit facilities are in place until October 2015. Consolidated SCE&G’s long-term debt portfolio has a weighted average maturity of over 18 years and bears an average cost of 6.18%. Most long-term debt, other than facility draws, effectively bears fixed interest rates or is swapped to fixed. To further preserve liquidity, Consolidated SCE&G rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.
SCE&G’s Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock, all of which is beneficially owned by SCANA.
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2011, approximately $58.8 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, 2011, the Bond Ratio was 5.37.
Financing Activities
In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.
In October 2011, SCE&G issued $30 million of 3.22% first mortgage bonds due October 18, 2021. Proceeds from the sale were used to redeem prior to maturity $30 million of 5.7% pollution control facilities revenue bonds due November 1, 2024 issued by Orangeburg County, South Carolina, on SCE&G’s behalf.
In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds due February 1, 2041, which constituted a reopening of the prior offering of $250 million of 5.45% first mortgage bonds issued in January 2011. Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance other capital expenditures and for general corporate purposes.
During 2011 Consolidated SCE&G experienced net cash inflows related to financing activities of $193 million primarily due to the issuance of short-term and long-term debt and contribution from parent, partially offset by repayment of long-term debt and payment of dividends.
SCE&G paid approximately $31 million in 2011 to settle interest rate contracts associated with the issuance of long-term debt.
For additional information on significant financing transactions, see Note 4 to the consolidated financial statements.
ENVIRONMENTAL MATTERS
Consolidated SCE&G’s regulated operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and 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, 2011, Consolidated SCE&G’s capital expenditures for environmental control equipment at its fossil fuel generating stations totaled $164.0 million. In addition, Consolidated SCE&G made expenditures to operate and maintain environmental control equipment at its fossil plants of $7.9 million during 2011, $6.5 million during 2010, and $5.6 million during 2009, which are included in “Other operation and maintenance” expense and made expenditures to handle waste ash of $8.7 million in 2011, $5.9 million in 2010, and $6.5 million in 2009, which are included in “Fuel used in electric generation.” In addition, included within “Other operation and maintenance” expense is an annual amortization of $1.4 million in each of 2011, 2010, and 2009 related to SCE&G’s recovery of MGP remediation costs as approved by the SCPSC. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for Consolidated SCE&G are $35.0 million for 2012 and $126.1 million for the four-year period 2013-2016. These expenditures are included in Consolidated SCE&G’s Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.
At the state level, no significant environmental legislation that would affect Consolidated SCE&G’s operations advanced during 2011. Consolidated SCE&G cannot predict whether such legislation will be introduced or enacted in 2012, or if new regulations or changes to existing regulations at the state level will be implemented in the coming year. Several regulatory initiatives at the federal level did advance in 2011 and more are expected to advance in 2012 as described below.
Air Quality
With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, Consolidated SCE&G is subject to 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. Other business and financial risks arising from such climate change could also arise. Consolidated SCE&G cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact Consolidated SCE&G, and the following discussion should not be considered all-inclusive.
From a regulatory perspective, Consolidated SCE&G continually monitors and evaluates current and projected emission levels and strives to comply with all state and federal regulations regarding those emissions. Consolidated SCE&G participates in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also has constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in pre-construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources.
In 2005, the EPA issued the CAIR, which required 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. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with the CSAPR and the reinstated CAIR. Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide. This new standard may require some of SCE&G’s smaller coal-fired units to reduce their sulfur dioxide emissions to a level to be determined by the EPA and/or DHEC. The costs incurred to comply with this new standard are expected to be recovered 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 Consolidated SCE&G’s electric system, as well as impacts on employees and customers and on its supply chain and many others. Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms.
To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties and has collected funds from customers for its storm damage reserve (see Note 2 to the consolidated financial statements). As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams, and applicable personnel participate in ongoing training and related simulations in advance of such storms, all in order to allow Consolidated SCE&G 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 in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by Consolidated SCE&G. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the new source performance standards of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.
To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether Consolidated SCE&G will be affected by the initiative in the future. Consolidated SCE&G believes that any enforcement action relative to its compliance with the CAA would be without merit. Consolidated SCE&G further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with NSR.
Water Quality
The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued and renewed for all of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for new cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The EPA has said that it will issue a rule by mid 2012 that modifies requirements for existing cooling water intake structures. Consolidated SCE&G is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include limitations to mixing zones and toxicity-based standards. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Consolidated SCE&G. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.
Hazardous and Solid Wastes
The EPA stated its intention to propose in late 2012 new federal regulations affecting the management and disposal of CCRs, such as ash. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.
The 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, 2011, the federal government has not accepted any spent fuel from Summer Station Unit 1 or any other nuclear generating facility, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability until at least 2017 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1 through dry cask storage or other technology as it becomes available.
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the state of South Carolina has a similar law. Consolidated SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean up. In addition, regulators from the EPA and other federal or state agencies periodically notify Consolidated SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates. Consolidated SCE&G has assessed the following matters:
Electric Operations
SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.
SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and expects to recover them through rates.
Gas Distribution
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2014 and will cost an additional $8.3 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements. At December 31, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9 million and are included in regulatory assets.
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.
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.
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 RSA allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.
Effective February 12, 2010, the PHMSA issued a final rule establishing integrity management requirements for gas distribution pipeline systems. SCE&G has developed a plan and procedures to ensure that it will be fully compliant with this rule. SCE&G believes that any additional costs incurred to comply with the rule will be recoverable through rates.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Following are descriptions of Consolidated SCE&G’s accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.
Utility Regulation
Consolidated SCE&G’s regulated operations record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities. In the future, in the event of deregulation or other changes in the regulatory environment, Consolidated SCE&G may no longer meet the criteria of accounting for rate-regulated utilities, and could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the results of operations, liquidity or financial position of Consolidated SCE&G’s Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. See Note 2 to the consolidated financial statements for a description of Consolidated SCE&G’s regulatory assets and liabilities, including those associated with Consolidated SCE&G’s environmental assessment program.
Consolidated SCE&G’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, Consolidated SCE&G could be required to write down its investment in those assets. Consolidated SCE&G cannot predict whether any write-downs would be necessary and, if they were, the extent to which they would affect Consolidated SCE&G’s results of operations in the period in which they would be recorded. As of December 31, 2011, Consolidated SCE&G’s net investments in fossil/hydro and nuclear generation assets were $3.1 billion and $1.8 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, SCE&G records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers for which they have not yet been billed. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2011 and 2010, accounts receivable included unbilled revenues of $117.8 million and $123.4 million, respectively, compared to total revenues of $2.8 billion for each of such years.
Nuclear Decommissioning
Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Among the factors that could change SCE&G’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and timing of cash flows. Changes in any of these estimates could significantly impact SCE&G’s financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).
SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site would be maintained over a period of 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
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 net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. SCANA’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $17.3 million ($13.9 million attributable to SCE&G) recorded in 2011 reflects the use of a 5.56% discount rate, derived using a cash flow matching technique, and an assumed 8.25% long-term rate of return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.31% in 2011 would have increased SCANA’s pension cost by $1.3 million. Had the assumed long-term rate of return on assets been 8.00%, SCANA’s pension cost for 2011 would have increased by $1.9 million.
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, 2010 and 2011 compared to the pension income recorded previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above the level that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.
The pension trust is adequately funded under current regulations, and no contributions have been required since 1997. Management does not anticipate the need to make significant pension contributions until after 2012.
SCANA accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 5.72%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $14.0 million for 2011. Had the selected discount rate been 5.47% (25 basis points lower than the discount rate referenced above), the expense for 2011 would have been $0.4 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.
Asset Retirement Obligations
Consolidated SCE&G accrues for the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation in accordance with applicable accounting guidance. The obligations are recognized at fair value in the period in which they are incurred and associated asset retirement costs are capitalized as a part of the carrying amount of the related long-lived assets. Because such obligations relate primarily to Consolidated SCE&G’s regulated utility operations, their recording has no significant impact on results of operations. As of December 31, 2011, Consolidated SCE&G has recorded AROs of $124 million for nuclear plant decommissioning (as discussed above) and $326 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded in accordance with the relevant accounting guidance are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments may be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for utilities remains in place.
OTHER MATTERS
Nuclear Generation
SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two 1,117-MW nuclear generation units to be constructed at the
site of Summer Station, 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. Under these agreements, SCE&G will have the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online.
SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction of the New Units. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.
As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.
The Consortium has recently performed an impact study, at SCE&G’s request, related to various cost and timing alternatives arising from the delay in the issuance date of the COL from mid-2011, which was the date assumed when the EPC Contract was signed in 2008, to the early-2012 issuance date currently anticipated by SCE&G. The impact study analyzed three scenarios, including (1) compressing the construction schedule for the first New Unit but retaining the original substantial completion dates set forth in the EPC Contract, (2) extending the substantial completion date for the first New Unit to accommodate the COL delay, or (3) delaying the substantial completion date of the first New Unit and accelerating the substantial completion date for the second New Unit. SCE&G has recently informed the Consortium that it intends to pursue scenario (3) and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.
The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site. These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium. While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million. SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (see Note 2 to the consolidated financial statements), will be recoverable through rates.
On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed above.
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.
In March 2011, a tsunami resulting from a massive earthquake severely damaged several nuclear generating units and their back-up cooling systems in Japan. The impact of the disaster is being evaluated world-wide, and numerous political and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at existing nuclear facilities, as well as those planned for construction. In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G is evaluating. SCE&G cannot predict what regulatory or other outcomes may be implemented in the United States, nor how such initiatives would impact SCE&G’s existing Summer Station or the licensing, construction or operation of the New Units.
In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactor to be used for the New Units. This certification is a necessary step before the NRC can issue a COL for the New Units. In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.
Fuel Contract
On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation.
Financial Regulatory Reform
In July 2010, Dodd-Frank became law. This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and requires numerous rule-makings by the Commodity Futures Trading Commission and the SEC to implement. Consolidated SCE&G is currently complying with these enacted regulations and intends to comply with regulations in the future but cannot predict when the final regulations will be issued or what requirements they will impose.
Off-Balance Sheet Transactions
Consolidated SCE&G does not hold significant investments in unconsolidated special purpose entities. Consolidated SCE&G does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, vehicles, equipment and rail cars, none of which are considered significant.
Claims and Litigation
For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS and Note 10 to the consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by Consolidated SCE&G described below are held for purposes other than trading.
The tables below provide information about long-term debt issued by Consolidated SCE&G which is sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
The above tables exclude long-term debt of $15 million at December 31, 2011 and $21 million at December 31, 2010, which amounts do not have stated interest rates associated with them.
For further discussion of Consolidated SCE&G’s long-term debt and interest rate derivatives, see ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES and also Notes 4 and 6 of the condensed consolidated financial statements.
Commodity Price Risk
The following table provides information about SCE&G’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value represents quoted market prices.
(a) Weighted average, in dollars
(b) Millions of dollars
SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 to the consolidated financial statements.
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 hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through weighted average cost of gas calculations. The offset to the change in fair value of these derivatives is deferred.
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, 2011 and 2010, 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, 2011. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 29, 2012
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
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
Organization and Principles of Consolidation
SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts of SCE&G, Fuel Company and GENCO. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs), and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.
GENCO owns a coal-fired electric generating station with a 605 megawatt net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $491 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.
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.
Utility Plant
Utility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. Consolidated SCE&G calculated AFC using average composite rates of 4.6% for 2011, 7.3% for 2010 and 7.4% for 2009. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.
Consolidated SCE&G records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.90% in 2011, 2.84% in 2010 and 2.95% in 2009.
Consolidated SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.
Jointly Owned Utility Plant
SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses are included in the corresponding operating expenses on its income statement.
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $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.
SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent of the output of the New Units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.
The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site. These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium. While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million. SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (see Note 2 to the consolidated financial statements), will be recoverable through rates.
Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6 million at December 31, 2011 and $77.9 million at December 31, 2010.
Major Maintenance
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the year ended December 31, 2011, SCE&G incurred $11.5 million for turbine maintenance. Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage. SCE&G accrued $1.2 million per month from July 2008 through July 2011 for its portion of the outages in the fall of 2009 and the spring of 2011. Total costs for the 2009 outage were
$32.7 million, of which SCE&G was responsible for $21.8 million. Total costs for the 2011 outage were $34.1 million, of which SCE&G was responsible for $22.7 million. In July 2011, SCE&G began accruing $1.2 million per month for its portion of the refueling planned for the fall of 2012. SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.
Nuclear Decommissioning
SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2011, 2010 and 2009) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.
Cash and Cash Equivalents
Consolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and notes.
Account Receivable
Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.
Income Taxes
Consolidated SCE&G is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.
Regulatory Assets and Regulatory Liabilities
Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.
Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Consolidated SCE&G records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.
Environmental
SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debits and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.
Income Statement Presentation
In its consolidated statements of income, Consolidated SCE&G presents the activities of its regulated businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).
Revenue Recognition
Consolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $117.8 million at December 31, 2011 and $123.4 million at December 31, 2010.
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 PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is deferred and included when making the next adjustment to the cost of gas factor. In addition, included in these deferred amounts are realized gains and losses incurred in SCE&G’s natural gas hedging program.
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers, and it will continue on a pilot basis unless modified or terminated by the SCPSC.
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.
New Accounting Matter
Effective for the first quarter of 2012, Consolidated SCE&G will adopt accounting guidance that revises how comprehensive income is presented in its financial statements. Consolidated SCE&G does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.
2. RATE AND OTHER REGULATORY MATTERS
SCE&G
Electric
SCE&G’s retail electric rates are established in part by using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs. In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011. SCE&G was allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period. In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011. On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. In February 2012, SCE&G requested authorization to decrease the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2012. The next annual hearing to review base rates for fuel costs is scheduled for March 22, 2012.
On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. Among other things, the SCPSC’s order (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.
On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs. By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition. The increase became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC its annual update on DSM programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net revenue, and the approved shared savings incentive for investing in such DSM Programs.
Electric - BLRA
In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of 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.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.
In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflected the removal of the contingency reserve and incorporated then identifiable capital costs of $173.9 million (in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.
On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed in Note 1 to the consolidated financial statements (e.g., those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site).
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:
Gas
SCE&G
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the billing cycle of November in the following years:
SCE&G’s natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.
Regulatory Assets and Regulatory Liabilities
Consolidated SCE&G’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, Consolidated SCE&G has recorded regulatory assets and liabilities which are summarized in the following tables. Substantially all of its regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections-electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods. These amounts are expected to be recovered in retail electric rates during the period January 2013 through April 2013. SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.
Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G. These regulatory assets are expected to be recovered over periods of up to approximately 23 years.
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 95 years.
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become larger at the election of the SCPSC.
Planned major maintenance related to certain fossil fuel turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.
Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate swaps designated as cash flow hedges. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.4 million at December 31, 2011 and are being recovered through utility rates over approximately 30 years. The remaining costs relate to Wateree Station, for which the Company will seek recovery in future proceedings before the SCPSC. SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.
Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.
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 and vegetation management expenditures in excess of amounts included in base rates. During the years ended December 31, 2011 and 2010, SCE&G applied costs of $6.4 million and $9.5 million, respectively, to the reserve. Pursuant to SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely pending future SCPSC action.
The SCPSC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G’s results of operations, liquidity or financial position in the period the write-off would be recorded.
3. EQUITY
Authorized shares of SCE&G common stock were 50 million as of December 31, 2011 and 2010. Authorized shares of SCE&G preferred stock were 20 million, none of which were issued or outstanding, as of December 31, 2011 and 2010.
SCE&G’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock.
With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2011, $58.8 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
4. LONG-TERM AND SHORT-TERM DEBT
Long-term debt by type with related weighted average interest rates and maturities at December 31 is as follows:
(a) Includes variable rate debt hedged by fixed rate swaps of $71.4 million in 2011 and 2010.
The annual amounts of long-term debt maturities for the years 2012 through 2016 are summarized as follows:
In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.
Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. Consolidated SCE&G is in compliance with all debt covenants.
Lines of Credit and Short-Term Borrowings
At December 31, 2011 and 2010, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.1 billion (of which $400 million relates to Fuel Company), which expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan
Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company). When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).
Consolidated SCE&G is obligated with respect to an aggregate $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company. These letters of credit expire, subject to renewal, in the fourth quarter of 2014.
The Company pays fees to banks as compensation for maintaining committed lines of credit.
5. INCOME TAXES
Total income tax expense attributable to income for 2011, 2010 and 2009 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 Consolidated SCE&G’s net deferred tax liability of $1.4 billion at December 31, 2011 and $1.2 billion at December 31, 2010 are as follows:
Consolidated SCE&G is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns. The IRS has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2007 are closed for additional assessment. With few exceptions, Consolidated SCE&G is no longer subject to state and local income tax examinations by tax authorities for years before 2008.
In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, SCE&G revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.
Changes to Unrecognized Tax Benefits
In connection with the change in method of accounting for certain repair costs for tax purposes referred to above, Consolidated SCE&G identified approximately $38 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. By December 31, 2012, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $38 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.
Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Consolidated SCE&G has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2010 or 2009. Consolidated SCE&G has accrued $2 million of interest expense related to unrecognized tax benefits in 2011.
6. DERIVATIVE FINANCIAL INSTRUMENTS
Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by Consolidated SCE&G. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries, including Consolidated SCE&G. The Risk Management Committee, which is comprised of certain officers, including the Consolidated SCE&G’s Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
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. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions. Cash settlement of commodity derivatives are classified as an operating activity in the consolidated statements of cash flows.
SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. These derivative financial instruments are not designated as hedges for accounting purposes.
Interest Rate Swaps
Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.
In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges. The effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions are recognized in income. Cash payments made or received upon termination of these financial instruments are classified as an investing activity in the consolidated statements of cash flows.
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
SCE&G was party to natural gas derivative contracts for 2,490,000 DT and 2,460,000 DT at December 31, 2011 and 2010, respectively. Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $471.4 million and $421.4 million at December 31, 2011 and 2010, respectively.
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 Consolidated SCE&G, and liability derivatives represent unrealized losses. In Consolidated SCE&G’s consolidated balance sheet, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.
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 were $(1.1) million, net of tax, in 2011 and were insignificant in 2010. These amounts are recorded within interest expense on the statement of income.
Credit Risk Considerations
Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require collateral to be provided upon the occurrence of specific events, primarily credit downgrades. As of December 31, 2011 and 2010, Consolidated SCE&G has posted $45.0 million and $0 million, respectively, of collateral related to derivatives with contingent provisions that are in a net liability position. If all of the contingent features underlying these instruments were fully triggered as of December 31, 2011 and 2010, Consolidated SCE&G would be required to post an additional $31.7 million and $34.9 million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2011 and 2010, are $76.7 million and $34.9 million, respectively.
7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition, there were no transfers of fair value amounts into or out of Levels 1 and 2 during any period presented.
Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2011 and December 31, 2010 were as follows:
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on discounted cash flow models with independently sourced data. Early settlement of long-term debt may not be possible or may not be considered prudent.
Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.
8. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension and Other Postretirement Benefit Plans
SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees. SCANA’s policy has been to fund the plan to the extent permitted by applicable federal income tax regulations, as determined by an independent actuary.
SCANA’s pension plan provides benefits under 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. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment.
In addition to pension benefits, SCE&G participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to certain active and retired employees. Retirees share in a portion of their medical care cost. SCANA provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.
Changes in Benefit Obligations
The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for retirement benefits and the accumulated benefit obligation for other postretirement benefits are presented below.
The accumulated benefit obligation for retirement benefits was $666.7 million at the end of 2011 and $649.0 million at the end of 2010. The accumulated retirement benefit obligation differs from the projected retirement benefit obligation above in that it reflects no assumptions about future compensation levels.
Significant assumptions used to determine the above benefit obligations are as follows:
An 8.2% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease gradually to 5.0% for 2020 and to remain at that level thereafter.
A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at December 31, 2011 by $1.4 million and at December 31, 2010 by $1.4 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 2011 by $1.2 million and at December 31, 2010 by $1.3 million.
Funded Status
Amounts recognized on the consolidated balance sheets consist of:
Amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2011 and 2010 were as follows:
In connection with the joint ownership of Summer Station, as of December 31, 2011 and 2010, SCE&G recorded within deferred debits $19.7 million and $13.0 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2011 and 2010, SCE&G also recorded within deferred debits $11.4 million and $10.7 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.
Changes in Fair Value of Plan Assets
Investment Policies and Strategies
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability for the pension plan, (2) maximizing return within reasonable and prudent levels of risk in order to minimize contributions, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, investment managers and performance expectations. Transactions involving certain types of investments are prohibited. Equity securities held by the pension plan during the periods presented did not include SCANA common stock.
The pension plan asset allocation at December 31, 2011 and 2010 and the target allocation for 2012 are as follows:
For 2012, the expected long-term rate of return on assets will be 8.25%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, and assumes an asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.
Fair Value Measurements
Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2011 and 2010, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
The Pension Plan values common stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds, common collective trusts and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. Government agency securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments. Hedge funds are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The valuation of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur.
Expected Cash Flows
The total benefits expected to be paid from the pension plan or from SCE&G’s assets for the other postretirement benefits plan, respectively, are as follows:
Expected Benefit Payments
* Net of participant contributions
Pension Plan Contributions
The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and SCE&G does not anticipate making significant contributions to the pension plan until after 2012.
Net Periodic Benefit Cost (Income)
SCE&G records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.
Components of Net Periodic Benefit Cost
In February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of increased pension cost by deferring as a regulatory asset the amount of pension cost above that which was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.
Other changes in plan assets and benefit obligations recognized in other comprehensive income were as follows:
Significant Assumptions Used in Determining Net Periodic Benefit Cost
The estimated amounts to be amortized from accumulated other comprehensive income into net periodic benefit cost in 2012 are as follows:
Other postretirement benefit costs are subject to annual per capita limits pursuant to plan design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $100,000.
Stock Purchase Savings Plan
SCE&G participates in a SCANA-sponsored defined contribution plan in which eligible employees may participate. Eligible employees may defer up to 25% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. SCE&G provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan for 2011, 2010 and 2009 were $17.3 million, $16.6 million and $16.6 million, respectively, and were made in the form of SCANA common stock.
9. SHARE-BASED COMPENSATION
SCE&G participates in the Plan which provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The Plan currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.
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 2009-2011, 2010-2012, and 2011-2013 performance cycles provide for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle. In each of the performance cycles, 20% of the performance award was granted in the form of restricted share units, which are liability awards payable in cash and are subject to forfeiture in the event of retirement or termination of employment prior to the end of the cycle, subject to exceptions for death, disability or change in control. The remaining 80% of the award was made in performance shares. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on the performance shares. Payout of performance share awards was determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%). Payouts under the 2009-2011 performance cycle were earned for each year that performance goals were met during the three-year cycle. Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2012.
Compensation cost of all these liability awards is recognized over their respective three-year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities related to similar prior programs were paid totaling $2.5 million in 2011, $2.4 million in 2010 and $1.7 million in 2009.
Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $4.0 million in 2011, $9.0 million in 2010 and $4.5 million in 2009. Fair value adjustments resulted in capitalized compensation costs of $0.2 million in 2011, $2.2 million in 2010 and $0.9 million in 2009.
Equity Awards
In the 2008-2010 performance cycle, 20% of the performance award was granted in the form of restricted (nonvested) shares rather than restricted share units. A summary of activity related to these 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. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized. SCE&G expensed compensation costs for nonvested shares of $0.1 million in each of 2010 and 2009. Tax benefits and capitalized compensation costs in 2010 and 2009 were not significant.
A summary of activity related to nonqualified stock options follows:
No stock options were granted or forfeited and all options were fully vested during the periods presented. The options expire ten years after their respective grant dates and all options currently outstanding will expire in 2012. At December 31, 2011, all outstanding options were currently exercisable at a price of $27.52, and had a weighted-average remaining contractual life of less than one year.
The exercise of stock options during the periods presented were satisfied using original issue shares. For the years ended December 31, 2011, 2010 and 2009, cash realized upon the exercise of options and related tax benefits were not significant.
10. COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the company’s nuclear power plant. Price-Anderson provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.
SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to the nuclear facility for property damage and outage costs up to $2.75 billion. In addition, a builder’s risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the Owners up to $500 million in limits of accidental property damage occurring during construction. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premiums, SCE&G’s portion of the prospective premium assessment would not exceed $37.3 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material impact on the Consolidated SCE&G’s results of operations, cash flows and financial position.
Environmental
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 in 2012. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the CAIR, which required 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. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule (CSAPR). This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with the Cross-State Air Pollution Rule and the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.
SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and expects to recover them through rates.
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2014 and will cost an additional $8.3 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements. At December 31, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9 million and are included in regulatory assets.
Claims and Litigation
In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. This settlement did not have a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition.
Consolidated SCE&G is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition.
Operating Lease Commitments
Consolidated SCE&G is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $10.8 million in 2011, $9.3 million in 2010 and $16.5 million in 2009. Future minimum rental payments under such leases are as follows:
Purchase Commitments
Consolidated SCE&G is obligated for purchase commitments that expire at various dates through 2034. Amounts expended for coal supply, nuclear fuel contracts, construction projects and other commitments totaled $717.8 million in 2011, $859.7 million in 2010 and $756.9 million in 2009. Future payments under such purchase commitments are as follows:
Asset Retirement Obligations
Consolidated SCE&G recognizes a liability for the fair value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s regulated utility operations. As of December 31, 2011, Consolidated SCE&G has recorded an ARO of approximately $124 million for nuclear plant decommissioning (see Note 1) and an ARO of approximately $326 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:
11. AFFILIATED TRANSACTIONS
CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. Such purchases totaled approximately $30.8 million in 2011, $32.0 million in 2010 and $30.4 million in 2009. SCE&G had approximately $2.5 million and $2.1 million payable to CGT for transportation services at December 31, 2011 and December 31, 2010, respectively.
SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $187.4 million in 2011, $182.5 million in 2010 and $160.8 million in 2009. SCE&G’s payables to SEMI for such purposes were $13.2 million and $16.1 million as of December 31, 2011 and 2010, respectively.
SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, both involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for these investments using the equity method. SCE&G’s receivables from these affiliates were $8.5 million at December 31, 2011 and insignificant at December 31, 2010. SCE&G’s payables to these affiliates were $8.6 million at December 31, 2011 and insignificant at December 31, 2010. SCE&G’s total purchases were $123.8 million in 2011 and $97.3 million in 2010. SCE&G’s total sales were $123.3 million in 2011 and $96.9 million in 2010.
Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions was not significant for any period presented. At December 31, 2011 and 2010, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $58.5 million and $71.0 million, respectively.
An affiliate processes and pays invoices for Consolidated SCE&G and is reimbursed by them. Consolidated SCE&G owed $43.0 million and $39.8 million to the affiliate at December 31, 2011 and 2010, respectively, for invoices paid by the affiliate on behalf of Consolidated SCE&G.
12. SEGMENT OF BUSINESS INFORMATION
Consolidated SCE&G’s reportable segments are listed in the following table. Consolidated SCE&G uses operating income to measure profitability for its regulated operations. Therefore, earnings available to common shareholders are not allocated to the Electric Operations and gas segments. Intersegment revenues were not significant.
Electric Operations is primarily engaged in the generation, transmission, and distribution of electricity, and is regulated by the SCPSC and FERC. Gas Distribution is engaged in the purchase and sale, primarily at retail, of natural gas, and is regulated by the SCPSC.
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, Consolidated SCE&G does not allocate interest charges, income tax expense or assets other than utility plant to its segments. Interest income is not reported by segment and is not material. Consolidated SCE&G’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.
The consolidated financial statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Segment Assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include amounts that are not allocated to the segments. Expenditures for Assets are adjusted for revisions to estimated cash flows related to asset retirement obligations, and totals not allocated to other segments.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
PART II,
ITEMS 9, 9A AND 9B
PART III
AND
PART IV
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not Applicable.
ITEM 9A. CONTROLS AND PROCEDURES
SCANA:
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2011, an evaluation was performed under the supervision and with the participation of SCANA’s management, including the CEO and CFO, of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCANA’s management, including the CEO and CFO, concluded that SCANA’s disclosure controls and procedures were effective as of December 31, 2011. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2011 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, 2011, the effectiveness of such structure and procedures. This management report follows.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of SCANA is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA’s internal control system was designed by or under the supervision of SCANA’s management, including the CEO and CFO, to provide reasonable assurance to SCANA’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.
SCANA’s management assessed the effectiveness of SCANA’s internal control over financial reporting as of December 31, 2011. 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, 2011, 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, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, 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, 2011 of the Company, and our report dated February 29, 2012, expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 29, 2012
SCE&G:
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2011, an evaluation was performed under the supervision and with the participation of SCE&G’s management, including the CEO and CFO, of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussions regarding required disclosure. Based on that evaluation, SCE&G’s management, including the CEO and CFO, concluded that SCE&G’s disclosure controls and procedures were effective as of December 31, 2011. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2011 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, 2011, the effectiveness of such structure and procedures. This management report follows.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of SCE&G is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G’s internal control system was designed by or under the supervision of SCE&G’s management, including the CEO and CFO, to provide reasonable assurance to SCE&G’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
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, 2011. 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, 2011, internal control over financial reporting is effective based on those criteria.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
A list of SCANA’s executive officers is in Part I of this annual report at page 26. The other information required by Item 10 is incorporated herein by reference to the captions “NOMINEES FOR DIRECTORS,” “CONTINUING DIRECTORS,” “BOARD MEETINGS-COMMITTEES OF THE BOARD”, “GOVERNANCE INFORMATION-SCANA’s Code of Conduct & Ethics” and “OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance” in SCANA’s definitive proxy statement for the 2012 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to the captions “COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION,” “COMPENSATION DISCUSSION AND ANALYSIS,” COMPENSATION COMMITTEE REPORT,” “SUMMARY COMPENSATION TABLE,” “2011 GRANTS OF PLAN-BASED AWARDS,” “OUTSTANDING EQUITY AWARDS AT 2011 FISCAL YEAR-END,” “2011 OPTION EXERCISES AND STOCK VESTED,” “PENSION BENEFITS,” “2011 NONQUALIFIED DEFERRED COMPENSATION,” and “POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL,” under the heading “EXECUTIVE COMPENSATION” and the heading “2011 DIRECTOR COMPENSATION” in SCANA’s definitive proxy statement for the 2012 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 is incorporated herein by reference to the caption “SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT” in SCANA’s definitive proxy statement for the 2012 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, 2011 are summarized as follows:
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated herein by reference to the caption “RELATED PARTY TRANSACTIONS” in SCANA’s definitive proxy statement for the 2012 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
SCANA: The information required by Item 14 is incorporated herein by reference to “PROPOSAL 4-APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in SCANA’s definitive proxy statement for the 2012 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, 2011 and 2010 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.
(1) Fees for audit services billed in 2011 and 2010 consisted of audits of annual financial statements, comfort letters, consents and other services related to SEC filings and accounting research.
(2) Fees primarily for employee benefit plan audits for 2011 and 2010.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed or furnished as a part of this Form 10-K:
(1) Financial Statements and Schedules:
The Report of Independent Registered Public Accounting Firm on the financial statements for SCANA and SCE&G are listed under Item 8 herein.
The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein.
The financial statement schedules filed as part of this report for SCANA and SCE&G are included below.
(2) Exhibits
Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the 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.
SCANA CORPORATION
BY:
/s/ K. B. MARSH
K. B. Marsh, Chairman of the Board, President, Chief Executive Officer, Chief Operating Officer and Director
DATE:
February 29, 2012
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/ K. B. MARSH
K. B. Marsh, Chairman of the Board, President, Chief Executive Officer, Chief Operating Officer and Director
(Principal Executive Officer)
/s/ J. E. ADDISON
J. E. Addison
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ J. E. SWAN, IV
J. E. Swan, IV
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick
J. M. Micali
J. A. Bennett
L. M. Miller
S. A. Decker
J. W. Roquemore
D. M. Hagood
M. K. Sloan
J. W. Martin, III
H. C. Stowe
* Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
DATE: February 29, 2012
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries or consolidated affiliates thereof.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY:
/s/ K. B. MARSH
K. B. Marsh, Chairman of the Board, Chief Executive Officer and Director
DATE:
February 29, 2012
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/ K. B. MARSH
K. B. Marsh, Chairman of the Board, Chief Executive Officer and Director
(Principal Executive Officer)
/s/ J. E. ADDISON
J. E. Addison
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ J. E. SWAN, IV
J. E. Swan, IV
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick
L. M. Miller
J. A. Bennett
J. W. Roquemore
S. A. Decker
M. K. Sloan
D. M. Hagood
H. C. Stowe
J. M. Micali
* Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
DATE: February 29, 2012
EXHIBIT INDEX
Exhibit
Applicable to
Form 10-K of
No.
SCANA
SCE&G
Description
3.01
X
Restated Articles of Incorporation of SCANA Corporation, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02
X
Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03
X
Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04
X
Restated Articles of Incorporation of South Carolina Electric & Gas Company, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05
X
By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.06
X
By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
4.01
X
X
Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)
4.02
X
Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York Mellon Trust Company, N. A. (successor to The Bank of New York), as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein)
4.03
X
First Supplemental Indenture dated as of November 1, 2009 to Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York Mellon Trust Company, N.A. (successor to The Bank of New York), as Trustee (Filed as Exhibit 99.01 to Registration Statement No. 333-174796 and incorporated by reference herein)
4.04
X
Junior Subordinated Indenture dated as of November 1, 2009 between SCANA Corporation and U.S. Bank National Association, as Trustee (Filed as Exhibit 99.02 to Registration Statement No. 333-174796 and incorporated by reference herein)
4.05
X
First Supplemental Indenture to Junior Subordinated Indenture referred to in Exhibit 4.04 dated as of November 1, 2009 (Filed as Exhibit 99.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
4.06
X
Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to The Bank of New York Mellon Trust Company, N. A. (as successor to NationsBank of Georgia, National Association), as Trustee (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)
4.07
X
First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)
4.08
X
Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)
Exhibit
Applicable to
Form 10-K of
No.
SCANA
SCE&G
Description
10.01
X
X
Engineering, Procurement and Construction Agreement, dated May 23, 2008, between South Carolina Electric & Gas Company, for itself and as Agent for the South Carolina Public Service Authority and a Consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed as Exhibit 10.01 to Form 10-Q/A for the quarter ended June 30, 2008 and incorporated by reference herein)
10.02
X
X
Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and South Carolina Electric & Gas Company for V. C. Summer AP1000 Nuclear Plant Units 2 & 3 (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed as Exhibit 10.01 to Form 10-Q/A for the quarter ended June 30, 2011 and incorporated by reference herein)
*10.03
X
X
SCANA Executive Deferred Compensation Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.04
X
X
SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.05 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.05
X
X
SCANA Director Compensation and Deferral Plan (including amendments through April 21, 2011) (Filed as Exhibit 4.05 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.06
X
X
SCANA Long-Term Equity Compensation Plan as amended and restated (including amendments through December 31, 2009) (Filed as Exhibit 99.06 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.07
X
X
SCANA Supplementary Executive Benefit Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.07 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.08
X
X
SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.08 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.09
X
X
SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.09 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.10
X
X
Description of SCANA Whole Life Option (Filed as Exhibit 10-F for the year ended December 31, 1991, under cover of Form SE, Filed No. 1-8809 and incorporated by reference herein)
10.11
X
Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 99.10 to Registration Statement No. 333-174796 and incorporated by reference herein)
12.01
X
Statement Re Computation of Ratios (Filed herewith)
12.02
X
Statement Re Computation of Ratios (Filed herewith)
Exhibit
Applicable to
Form 10-K of
No.
SCANA
SCE&G
Description
21.01
X
Subsidiaries of the registrant (Filed herewith under the heading “Corporate Structure” in Part I, Item I of this Form 10-K and incorporated by reference herein)
23.01
X
Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith)
23.02
X
Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith)
24.01
X
Power of Attorney (Filed herewith)
24.02
X
Power of Attorney (Filed herewith)
31.01
X
Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02
X
Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03
X
Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04
X
Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01
X
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02
X
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.03
X
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.04
X
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
101. INS**
X
X
XBRL Instance Document
101. SCH**
X
X
XBRL Taxonomy Extension Schema
101. CAL**
X
X
XBRL Taxonomy Extension Calculation Linkbase
101. DEF**
X
X
XBRL Taxonomy Extension Definition Linkbase
101. LAB**
X
X
XBRL Taxonomy Extension Label Linkbase
101. PRE**
X
X
XBRL Taxonomy Extension Presentation Linkbase
*
Management Contract or Compensatory Plan or Arrangement
**
Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.