SCANA CORP
ITEM 1. BUSINESS
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; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC) as soon as reasonably practicable after these reports are filed or furnished.
SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s new nuclear project and other matters of interest to investors on SCANA’s website. On SCANA’s homepage, there is a yellow box containing links to the Nuclear Development and Other Investor Information sections of the website. The Nuclear Development section contains a yellow box with a link to project news and updates. The Other Investor Information section of the website contains a link to recent investor-related information that cannot be found at other areas of the website. Some of the information that will be posted from time to time, including the quarterly reports that SCE&G submits to the SCPSC and the ORS in connection with the new nuclear project, may be deemed to be material information that has not otherwise become public. Investors, media and other interested persons are encouraged to review this information and can sign up, under the Investor Relations Section of the website, for an email alert when there is a new posting in the Nuclear Development and Other Investor Information yellow box.
CORPORATE STRUCTURE AND SEGMENTS OF BUSINESS
SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA and its subsidiaries had full-time, permanent employees of 5,910 as of February 20, 2017 and 5,829 as of February 19, 2016. SCANA does not directly own or operate any significant physical properties, but it holds directly all of the capital stock of its subsidiaries, including the subsidiaries described below.
Regulated Utilities
SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 709,000 customers and the purchase, sale and transportation of natural gas to approximately 358,000 customers (each as of December 31, 2016). 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 16,000 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 23,000 square miles. More than 3.4 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, automotive and tire and fabricated metal products.
GENCO owns Williams Station and sells electricity, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a unit power sales agreement and related operating agreement. 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 550,000 residential, commercial and industrial customers (as of December 31, 2016). PSNC Energy serves 28 franchised counties covering approximately 12,000 square miles in North Carolina. The predominant industries served by PSNC Energy include educational services, food products, health services, automotive, chemicals, non-woven textiles, electrical generation and construction.
Nonregulated Businesses
SCANA Energy markets natural gas in the southeast and provides energy-related services. A division of SCANA Energy sells natural gas to approximately 450,000 customers (as of December 31, 2016) in Georgia’s deregulated natural gas market.
SCANA Services, Inc. provides administrative and management services to SCANA's other subsidiaries.
For information with respect to major segments of business, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 12 of the consolidated financial statements. All such information is incorporated herein by reference.
ELECTRIC OPERATIONS
Electric Sales
SCE&G’s sales of electricity and margins earned from those sales by customer classification as percentages of electric revenues were as follows:
Sales
Margins
Customer Classification
Residential
%
%
%
%
Commercial
%
%
%
%
Industrial
%
%
%
%
Sales for resale
%
%
%
%
Other
%
%
%
%
Total
%
%
%
%
Sales for resale include sales to three municipalities and one electric cooperative. Short-term system sales and margins were not significant for either period presented.
During 2016 SCE&G experienced a net increase of approximately 11,000 electric customers (growth rate of 1.6%), increasing its total number of electric customers to approximately 709,000 at year end.
The following projections assume normal weather where applicable. For the period 2016 to 2017, SCE&G projects a retail kWh sales decrease of approximately 0.1% and customer growth of 1.5%. For the period 2017-2019, SCE&G projects total territorial kWh sales of electricity to increase 0.3% annually, total retail sales to grow 0.3% annually, total electric customer base to increase 1.6% annually and territorial peak load (summer, in MW) to increase 1.6% annually. SCE&G’s goal is to maintain a planning reserve margin of between 14% and 20%; however, 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 extends over a large part of the central, southern and southwestern portions of South Carolina. The system interconnects with Duke Energy Carolinas, LLC, Duke Energy Progress, LLC, Santee Cooper, Georgia Power Company and the Southeastern Power Administration’s Clarks Hill (Thurmond) Project. SCE&G is a member 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. The regional entities and all members of NERC work to safeguard the reliability of the bulk power systems throughout North America.
Fuel Costs and Fuel Supply
The average cost of various fuels and the weighted average cost of all fuels (including oil) were as follows:
Cost of Fuel Used
Per MMBTU:
Nuclear
$
0.98
$
0.95
$
1.01
Coal
3.41
3.81
3.90
Natural Gas
3.02
3.26
5.19
All Fuels (weighted average)
2.41
3.01
3.62
Per Ton: Coal
84.62
95.69
96.74
Per MCF: Gas
3.11
3.35
5.30
For a listing of the Company's generating facilities, see the Electric Properties section within Item 2. Properties. For information on actual and projected sources and percentages of total MWh generation by each category of fuel, see Electric Operations - Environmental within the Overview section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
In 2016, coal was primarily obtained through long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia, and West Virginia. These contracts provide for approximately 1.4 million tons annually. Sulfur restrictions on the contract coal range from 1.0% to 1.6%. These contracts expire at various times through 2018. Spot market purchases may occur when needed or when prices are believed to be favorable. The Company relies on unit trains and, in some cases, trucks and barges for coal deliveries.
SCANA and SCE&G believe that electric operations comply with all applicable regulations relating to the discharge of SO2 and NOX . See additional discussion at Environmental Matters in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
SCE&G, for itself and as agent for Santee Cooper, and WEC are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, SCE&G supplies enriched products to WEC and WEC supplies nuclear fuel assemblies for Unit 1 and is under contract to supply assemblies for the New Units. WEC 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 Unit 1 and the New Units through 2033. SCE&G is dependent upon WEC for providing fuel assemblies for the new AP1000 reactors in the New Units in the current and anticipated future absence of other commercially viable sources.
In addition, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. 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 stores spent nuclear fuel in its on-site spent-fuel pool, and has constructed a dry cask storage facility to accommodate the spent fuel output for the life of Unit 1. In addition, Unit 1 has sufficient on-site 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 the Environmental section of Note 10 to the consolidated financial statements.
SCE&G also uses long-term power purchase agreements to ensure that adequate power supply resources are in place to meet load obligations and reserve requirements. As of January 1, 2017, SCE&G had such agreements in place for 325 MW of capacity (expiring at various times through 2020). In addition, SCE&G had the ability to purchase an additional 204 MW of capacity under these agreements.
GAS OPERATIONS
Gas Sales-Regulated
Regulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported were as follows:
SCANA
SCE&G
Customer Classification
Residential
57.9
%
57.0
%
48.3
%
47.9
%
Commercial
26.4
%
26.8
%
28.6
%
28.0
%
Industrial
10.4
%
11.0
%
19.5
%
20.6
%
Transportation Gas
5.3
%
5.2
%
3.6
%
3.5
%
Total
100.0
%
100.0
%
100.0
%
100.0
%
For the period 2017-2019, SCANA projects total consolidated sales of regulated natural gas in MMBTUs to increase 4.1% annually (excluding transportation and assuming normal weather). Annual projected increases over such period in MMBTU sales include residential of 2.5%, commercial of 0.8% and industrial of 10.7%.
For the period 2017-2019, SCE&G projects total consolidated sales of regulated natural gas in MMBTUs to increase 2.7% annually (excluding transportation and assuming normal weather). Annual projected increases over such period in MMBTU sales include residential of 2.4%, commercial of 0.7% and industrial of 4.3%.
For the period 2017-2019, each of SCANA’s and SCE&G’s total regulated natural gas customer base is projected to increase 2.6% annually. During 2016, SCANA recorded a net increase of approximately 26,000 regulated gas customers (growth rate of 2.9%), increasing the number of its regulated gas customers to approximately 907,000. Of this increase, SCE&G recorded a net increase of approximately 10,000 gas customers (growth rate of 2.9%), increasing the number of its total gas customers to approximately 358,000 (as of December 31, 2016).
Demand for gas changes primarily due to weather and the price relationship between gas and alternate fuels.
Gas Cost and Supply
SCE&G purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market based prices. The gas is delivered to South Carolina through firm transportation agreements with Southern Natural (expiring in 2018), Transco (expiring at various times through 2031) and DCGT (expiring at various times through 2036). The maximum daily volume of gas that SCE&G is entitled to transport under these contracts is 212,194 MMBTU from Southern Natural, 104,652 MMBTU from Transco and 461,727 MMBTU from DCGT. 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 SCANA Energy is entitled to transport under its service agreements (expiring at various times through 2023) on a firm basis is 771,627 MMBTU. Additional natural gas volumes may be delivered as capacity is available through interruptible transportation.
SCE&G purchased natural gas, including fixed transportation, at an average cost of $3.46 per MMBTU during 2016 and $3.67 per MMBTU during 2015.
To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCE&G has 5,502,600 MMBTU of natural gas storage capacity on the systems of Southern Natural and Transco. Approximately 3,806,800 MMBTU of gas were in storage on December 31, 2016. SCE&G supplements its supplies of natural gas with two LNG storage facilities, one of which has liquefaction capability. Approximately 1,833,400 MMBTU (liquefied equivalent) of gas were in storage on December 31, 2016. For a discussion of SCE&G's natural gas storage capacity, see Item 2. Properties.
PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at market based prices and on a long-term basis for reliability assurance at first of the month index prices plus a reservation charge in certain cases. Transco transports natural gas to North Carolina through transportation agreements with varying expiration dates through 2031. On a peak day, PSNC Energy is capable of receiving daily transportation volumes of natural gas under these contracts, utilizing firm contracts of 710,062 MMBTU from Transco.
PSNC Energy purchased natural gas, including fixed transportation, at an average cost of $3.73 per MMBTU during 2016 compared to $4.12 per MMBTU during 2015.
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 Transmission, Inc., Columbia Gas Transmission, Transco and Spectra Energy provide for storage capacity of approximately 13,000,000 MMBTU. Approximately 9,000,000 MMBTU of gas were in storage under these agreements at December 31, 2016. PSNC Energy also maintains LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG which provides 1,300,000 MMBTU (liquefied equivalent) of storage space. Approximately 1,100,000 MMBTU (liquefied equivalent) were in storage under these agreements at December 31, 2016. Approximately 900,000 MMBTU (liquefied equivalent) of gas were in storage at PSNC Energy's LNG storage facility at December 31, 2016. For a discussion of PSNC Energy's LNG storage capacity, see Item 2. Properties.
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
SCANA Energy markets natural gas and provides energy-related services in the Southeast. In addition, a division of SCANA Energy markets natural gas to approximately 450,000 customers (as of December 31, 2016) in Georgia’s natural gas market. Georgia’s natural gas market includes approximately 1.6 million customers.
Risk Management
For a discussion of risk management policies and procedures, see Note 6 to the consolidated financial statements.
REGULATION
Regulatory jurisdictions to which SCANA and its subsidiaries are subject are described in the Regulatory Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations.
SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2018.
SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The licenses expire as follows:
Project
License
Expiration
Saluda (Lake Murray)
*
Fairfield Pumped Storage/Parr Shoals
Stevens Creek
Neal Shoals
* SCE&G operates the Saluda hydroelectric project under an annual license while its long-term re-licensing application is being reviewed by FERC.
At the termination of a license under the Federal Power Act, FERC may extend or issue a new license to the previous licensee, or 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.
RATE MATTERS
For a discussion of the impact of various rate matters, see the Regulatory Matters section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 2 to the consolidated financial statements.
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, and the cost of emission allowances used for SO2, NOX, mercury and particulates. In addition, the statutory definition of fuel cost allows electric utilities to recover avoided costs under the Public Utility Regulatory Policy Act of 1978, as well as costs incurred as a result of offering DER and net metering programs to its customers. SCE&G may request a formal proceeding concerning its fuel costs at any time.
Fuel cost recovery procedures related to the Company's natural gas operations along with related rate proceedings by the SCPSC and NCUC are described in Note 2 to the consolidated financial statements.
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 any new or pending regulations or standards upon existing operations cannot be predicted. For a discussion of how these regulations and standards may impact SCANA and SCE&G (including capital expenditures necessitated thereby), see the Environmental Matters section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 10 to the consolidated financial statements.
OTHER MATTERS
Insurance coverage for SCE&G's nuclear units is described in Note 10 to the consolidated financial statements.
For a discussion of the impact of competition, see the Overview section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 1A. RISK FACTORS
The risk factors that follow relate in each case to the Company, and where indicated the risk factors also relate to Consolidated SCE&G.
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 infrastructure, are significant and these projects are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of these 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. In particular, SCE&G and Santee Cooper have agreed to jointly own, contract the design and construction of, and operate the New Units, which will be two 1,250 MW (1,117 MW, net) nuclear units at SCE&G’s Summer Station, in pursuit of which they have committed and are continuing to commit significant resources. In addition, construction of significant new transmission infrastructure is necessary to support the New Units and is 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 adhere to established budgets and construction schedules may be affected by many variables, such as the regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them 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/or financial stability, unforeseen difficulties meeting critical regulatory requirements, contract disputes and litigation, and changes in key contractors or subcontractors. 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, adverse changes in applicable laws and regulations, new or enhanced environmental or regulatory requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. Some of the foregoing issues have been experienced in the construction of the New Units. A discussion of certain of those matters can be found under New Nuclear Construction in Note 10 to the consolidated financial statements.
Should the construction of the New Units materially and adversely deviate from the SCPSC-approved schedules (by more than 18 months), estimates, and projections, the SCPSC could disallow the additional capital costs that result from the deviations to the extent that it is deemed that the Company's failure to anticipate or avoid the deviation, or to minimize the resulting expenses, was imprudent, considering the information available at the time that the Company could have acted to avoid the deviation or minimize its effect. Depending upon the magnitude of any such disallowed capital costs, the Company could be moved to evaluate the prudency of continuation, adjustment to, or termination of the project.
Furthermore, jointly owned projects, such as the current construction of the New Units, are subject to risks including that one or more of the joint owners becomes either unable or unwilling to continue to fund project financial commitments, that new joint owners cannot be secured at equivalent financial terms, or that changes in the joint ownership 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 to effectively manage and complete our capital projects, our results of operations, cash flows and financial condition, as well as our qualifications for applicable governmental programs and benefits, such as production tax credits, may be adversely affected.
Recent announcements by Toshiba, the parent company of WEC and the guarantor of WEC's payment obligations with respect to the above construction project for New Units at SCE&G’s Summer Station, related to deterioration in its financial position and liquidity indicate heightened risks and substantial uncertainties with respect to the cost, timing, construction and/or completion of the New Units.
Following several announcements and related media reports, on February 14, 2017, Toshiba, the parent company of WEC and the guarantor of its payment obligations with respect to the EPC Contract, announced that it expects to record a multi-billion dollar impairment loss associated with the construction of the New Units and the two additional AP1000 units being constructed by WEC for another company in the United States.
In December 2015, WEC acquired 100% of the shares of Stone & Webster from CB&I. On December 27, 2016, Toshiba announced the possibility that the goodwill resulting from the transaction would reach a level of several billion U.S. dollars and would be impaired, leaving Toshiba with negative shareholders' equity. The increase to the amount of goodwill resulted from WEC’s analysis that demonstrated the cost to complete the four Westinghouse AP1000 new nuclear plants in the United States would far surpass the original estimates for construction. In public statements in 2017, Toshiba attributed the cost overruns to, among other things, higher labor costs arising from lower than anticipated work efficiency and the inability to improve such work efficiency over time. While the final figures related to the impairment remain subject to adjustment, Toshiba’s February 14, 2017 announcement indicated it anticipates it will record a loss in excess of $6 billion.
Toshiba’s credit ratings, already below investment grade following disclosures of accounting and internal control irregularities in 2015, were further reduced in January 2017, and the Company and Consolidated SCE&G expect that Toshiba will continue to experience negative financial repercussions resulting from these developments. In response, Toshiba has announced, among other things, its plan to monetize portions of its businesses to generate cash. It has also indicated that it will not take on future nuclear construction projects and that it will significantly alter its risk management oversight of its nuclear business. The ability of WEC and Toshiba to successfully respond to these developments will continue to impact Toshiba's credit ratings, creditworthiness, financial stability and viability. There can be no assurance that Toshiba's or WEC's actions will be sufficient such that Toshiba's lenders and creditors will continue to provide necessary liquidity. In particular, these losses raise uncertainty with respect to Toshiba’s ability to perform under its guaranty of WEC's payment obligations to the Company and Consolidated SCE&G, and further highlight the risks to the Company and Consolidated SCE&G related to the construction schedule and WEC’s ability to continue with and/or complete the construction of the New Units. Adverse changes in contracts, contractors and subcontractors, and to the project schedule could result. Additionally, contractual disputes and litigation could follow.
In addition to the project risks highlighted in Toshiba’s disclosures surrounding the large losses described above, additional risks and uncertainties regarding the project schedule are evident. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, are not likely to be met. Instead, revised substantial completion dates of April 2020 and December 2020 are reflected within WEC’s revised project schedule. While these later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits, there remains substantial uncertainty as to WEC’s ability to meet these dates given its historical inability to meet forecasted productivity and work force efficiency levels.
SCE&G and Santee Cooper, the co-owner of the New Units, continue to evaluate various actions which might be taken in the event that Toshiba and WEC are unable or unwilling to complete the project. These include completing the work under any of several arrangements with other contractors or, were it determined to be prudent, halting the project, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA. Any significant delay in the timing of construction or any determination by the SCPSC to disallow the recovery of costs would adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial condition.
Commodity price changes, delays in delivery of commodities, commodity availability 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, uranium and other commodity prices (as well as their transportation costs), availability and deliverability. 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 purchased power and fuel (including transportation) used in electric generation through retail customers’ bills, but purchased power and 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 result in 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 condition.
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, in both our regulated and deregulated natural gas markets, increases in gas costs affect total retail prices and therefore the competitive position of gas relative to electricity and other forms of energy. Accordingly, customers able to do so may switch to alternate forms of energy and reduce their usage of gas from the Company and Consolidated SCE&G. Customers on a volumetric rate structure unable to switch to alternate fuels or suppliers may reduce their usage of gas from the Company and Consolidated SCE&G. A regulatory mechanism applies to residential and commercial customers at PSNC Energy to mitigate the earnings impact of an increase or decrease in gas usage.
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, increased demand for these reagents, combined with the increased demand for low sulfur coal, may result in higher costs for coal and reagents used for compliance purposes.
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 financial market risks. The Company also uses such derivative instruments to manage certain commodity (i.e., natural gas) market risk. We could be required to provide cash collateral or recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and financial contracts or if a counterparty fails to perform under a contract.
The Company strives to manage commodity price exposure by establishing risk limits and utilizing various financial instruments (exchange traded and over-the-counter instruments) to hedge physical obligations and reduce price volatility. 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 adversely impacted.
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, the Department of Homeland Security, CFTC and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by the state governments of South Carolina, North Carolina and Georgia via regulatory agencies, state environmental agencies, 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 businesses. In addition to many other aspects of our businesses, these requirements impact the services mandated or offered to our customers, and the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our electric and natural gas systems, the physical and cyber security of key assets, customer conservation through DSM Programs, information security, the issuance of securities and borrowing of money, financial reporting, interactions among affiliates, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual and potentially costly to effect compliance. Non-compliance with these requirements by third parties, such as our contractors, vendors and agents, may subject the Company and Consolidated SCE&G to operational risks and to liability. 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. Non-compliance with these laws and regulations could result in fines, litigation, loss of licenses or permits, mandated capital expenditures and other adverse business outcomes, as well as reputational damage, which could adversely affect the cash flows, results of operations, and financial condition of the Company and Consolidated SCE&G.
Furthermore, changes in or uncertainty in monetary, fiscal, or regulatory policies of the Federal government may adversely affect the debt and equity markets and the economic climate for the nation, region or particular industries, such as ours or those of our customers. The Company and Consolidated SCE&G could be adversely impacted by changes in tax policy, such as the loss of production tax credits related to the construction of the New Units.
The Company and Consolidated SCE&G are subject to extensive rate regulation which could adversely affect operations. Large capital projects, results of DSM Programs, results of DER programs, and/or increases in operating costs may lead to requests for regulatory relief, such as rate increases, which may be denied, in whole or part, by rate regulators. Rate increases may also result in reductions in customer usage of electricity or gas, legislative action and lawsuits.
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. In addition, the construction of the New Units by SCE&G is subject to rate regulation by the SCPSC via the BLRA. Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the NRC and SCPSC. SCE&G's electric transmission system is subject to extensive regulations and oversight from the SCPSC, NERC and FERC. Implementing and maintaining compliance with the NERC's mandatory reliability standards, enforced by FERC, for bulk electric systems could result in higher operating costs and capital expenditures. Non-compliance with these standards could subject SCE&G to substantial monetary penalties. 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.
Furthermore, Dodd-Frank affects the use and reporting of derivative instruments. The regulations under this legislation provide for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and require numerous rule-makings by the CFTC and the SEC to implement, many of which are still pending final action by those federal agencies. The Company and Consolidated SCE&G have determined that they meet the end-user exception to mandatory clearing of swaps under Dodd-Frank. In addition, the Company and Consolidated SCE&G have taken steps to ensure that they are not the party required to report these transactions in real-time (the "reporting party") by transacting solely with swap dealers and major swap participants, when possible, as well as entering into reporting party agreements with counterparties who also are not swap dealers or major swap participants, which establishes that those counterparties are obligated to report the transactions in accordance with applicable Dodd-Frank regulations. While these actions minimize the reporting obligations of the Company, they do not eliminate required recordkeeping for any Dodd-Frank regulated transactions. Despite qualifying for the end-user exception to mandatory clearing and ensuring that neither the Company nor Consolidated
SCE&G is the reporting party to a transaction required to be reported in real-time, we cannot predict when the final regulations will be issued or what requirements they will impose.
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 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 NOX, SO2, mercury and particulate matter). Some form of regulation is expected at the federal and state levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO2 from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO2 per MWh. No new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national CO2 emissions by 32% from 2005 levels by 2030. However, on February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. Also, 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 has yet been enacted. In April 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's rule for cooling water intake structures to meet the best technology available became effective in October 2014, and the EPA also issued a final rule in December 2014 regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA finalized new standards under the CWA governing effluent limitation guidelines for electric generating units in September 2015.
Compliance with these environmental laws and regulations requires us to commit significant resources 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 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 businesses 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. In June 2014 the State of South Carolina enacted legislation known as Act 236 with the stated goal for each investor-owned utility to supply up to 2% of its 5-year average retail peak demand with renewable electric generation resources by the end of 2020. A utility, at its option, may supply an additional 1% during this period. Such renewable energy may not be readily available in our service territories and could be costly to build, finance, acquire, integrate, and/or operate. Resulting increases in the price of electricity to recover the cost of these types of generation, as approved by regulatory commissions, could result in lower usage of electricity by our customers. In addition, DER generation at customers’ facilities could result in the loss of sales to those customers. Compliance with potential future portfolio standards could significantly impact our capital expenditures and our results of operations and financial condition. Utility scale solar development companies are currently working in South Carolina to develop projects in SCE&G's service territory. The integration of those resources at high penetration levels may be challenging.
The compliance costs of these environmental laws and regulations are important considerations in the Company's and Consolidated SCE&G's strategic planning and, as a result, significantly affect the decisions to construct, operate, and retire facilities, including generating facilities. In effecting compliance with MATS, SCE&G has retired three of its oldest and smallest coal-fired units and converted three others such that they may be gas-fired.
The Company and Consolidated SCE&G are vulnerable to interest rate increases, which would increase our borrowing costs, and we 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 Consolidated 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 businesses. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.
Disruptions in the capital markets and its actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial condition, 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 currently 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, rating 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. Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including regulatory environment, capital structure and the ability to meet liquidity requirements. Changes in the regulatory environment or deterioration of our rated companies’ commonly monitored financial credit metrics and adverse developments with respect to nuclear construction could negatively affect their debt ratings. If these rating agencies were to downgrade any of these ratings, particularly to below investment grade for long-term ratings, borrowing costs on new issuances would increase, which could adversely impact financial results, and the potential pool of investors and funding sources could decrease.
The Company and Consolidated SCE&G are engaged in activities for which they have claimed, and expect to claim in the future, research and experimentation tax deductions and credits which are the subject of uncertainty and which may be considered controversial by the taxing authorities. The outcome of those uncertainties could adversely impact cash flows and financial condition.
The Company and Consolidated SCE&G have claimed significant research and experimentation tax deductions and credits related to the ongoing design and construction activities of the New Units. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. (See also Uncertain income tax positions within the Critical Accounting Policies and Estimates section of Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 5 to the consolidated financial statements.)
These tax claims primarily involve the timing of recognition of tax deductions rather than permanent tax attributes. The permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to them, have been deferred within regulatory assets. As such, these claims have not had, and are not expected to have in the future, significant direct effects on the Company’s and Consolidated SCE&G’s results of operations. Nonetheless, the claims have contributed significantly to the Company’s and Consolidated SCE&G’s cash flows and are expected to continue to do so through the remainder of the New Units’ construction period. Also, the claims have provided a significant source of capital and have lessened the level of debt and equity financing that the Company and Consolidated SCE&G have needed to raise in the financial markets. Future claims are expected to provide similar tax benefits.
However, the claims made to date are under examination, and may be considered controversial, by the IRS. It is expected that the IRS will also examine future claims. To the extent that the claims are not sustained on examination or through any subsequent appeal, the Company and Consolidated SCE&G will be required to repay any cash received for tax benefit claims which are ultimately disallowed, along with interest on those amounts. Such amounts could be significant and could adversely affect the Company's and Consolidated SCE&G's cash flows and financial condition. In certain circumstances, which management considers to be remote, penalties for underpayment of income taxes could also be assessed. Additionally, in such circumstances, the Company and Consolidated SCE&G may need to access the capital markets to fund those tax and interest payments, which could in turn adversely impact their ability to access financial markets for other purposes.
Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.
The Company has delivered less gas and, in deregulated markets, received lower prices for natural gas when weather conditions have been milder than normal, and as a consequence earned less income from those operations. Mild weather in the future could adversely impact the revenues and results of operations and harm the financial condition of the Company and Consolidated SCE&G. Hot or cold weather could result in higher bills for customers and result in higher write-offs of receivables and in a greater number of disconnections for non-payment. 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 hurricanes or other significant weather events, electromagnetic events or the 2011 earthquake and tsunami in Japan) or man-made mishaps (such as the San Bruno, California natural gas transmission pipeline failure, electric utility companies' ash pond failures, and cyber-security failures experienced by many businesses) could have direct significant impacts on the Company and Consolidated SCE&G and on our key contractors and suppliers or could impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial condition, 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 via an RTO/ISO is in effect across much of the country, but the Southeastern utilities have retained the traditional bundled, vertically integrated structure. Should an RTO/ISO-market be implemented in the Southeast, potential risks emerge from reliance on volatile wholesale market prices as well as increased costs associated with new delivery transmission and distribution infrastructure.
Some states have also mandated or encouraged unbundled retail competition. Should this occur in South Carolina or North Carolina, 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 could be required.
The Company and Consolidated SCE&G are subject to the risk of loss of sales due to the growth of distributed generation especially in the form of renewable power such as solar photovoltaic systems, which systems have undergone a rapid decline in their costs. As a result of federal and state subsidies, potential regulations allowing third-party retail sales, and
advances in distributed generation technology, the growth of such distributed generation could be significant in the future. Such growth will lessen Company and Consolidated SCE&G sales and will slow growth, potentially causing higher rates to customers.
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. Adverse events, economic or otherwise, may also affect the operations of suppliers and key customers. Such events may result in the loss of suppliers or customers, in higher costs charged by suppliers, in changes to customer usage patterns and in the failure of customers to make timely payments to us. With respect to the Company, such events also could adversely impact the results of operations through the recording of a goodwill or other asset impairment. 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, legislative actions (including tax reform), 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 and demand side management 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. For instance, improvements in energy storage technology, if realized, could have dramatic impacts on the viability of and growth in distributed generation.
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 that are 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 adversely impacted.
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 equipment failure, information systems failure or security breach, operator error, natural disasters, and the effects of a pandemic, terrorist attack or cyber attack on our workforce or facilities or on vendors and suppliers necessary 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 equipment, or other equipment or processes which would result in performance below assumed levels of output or efficiency. The operation of the New Units or the integration of a significant amount of distributed generation into our systems may entail additional cycling of our coal-fired generation facilities and may thereby increase the number of unplanned outages at those facilities. 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. These purchases are subject to state regulatory prudency reviews for recovery through rates. 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. Similarly, a natural gas 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 and Consolidated SCE&G's revenues, results of operations, cash flows, and financial condition. Insurance may not be available or adequate to mitigate the adverse impacts of these events.
A failure of the Company and Consolidated SCE&G to maintain the physical and cyber security of its operations may result in the failure of operations, damage to equipment, or loss of information, and could result in a significant adverse impact to the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows.
The Company and Consolidated SCE&G depend on maintaining the physical and cyber security of their operations and assets. As much of our business is part of the nation's critical infrastructure, the loss or impairment of the assets associated with that portion of our businesses could have serious adverse impacts on the customers and communities that we serve. Virtually all of the Company's and Consolidated SCE&G's operations are dependent in some manner upon our cyber systems, which encompass electric and gas operations, nuclear and fossil fuel generating plants, human resource and customer systems and databases, information system networks, and systems containing confidential corporate information. Cyber systems, such as those of the Company and Consolidated SCE&G, are often targets of malicious cyber attacks. A successful physical or cyber attack could lead to outages, failure of operations of all or portions of our businesses, damage to key components and equipment, and exposure of confidential customer, vendor, shareholder, employee, or corporate information. The Company and Consolidated SCE&G may not be readily able to recover from such events. In addition, the failure to secure our operations from such physical and cyber events may cause us reputational damage. Litigation, penalties and claims from a number of parties, including customers, regulators and shareholders, may ensue. Insurance may not be adequate to mitigate the adverse impacts of these events. As a result, the Company's and Consolidated SCE&G's financial condition, results of operations, and cash flows may be adversely affected.
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 SCANA Energy, to pay dividends or to 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 2016, Unit 1 provided approximately 5.8 million MWh, or 25% of our generation. When the New Units are completed, our generating capacity and the percentage of total generating capacity represented by nuclear sources are 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;
•
The possibility that new laws and regulations could be enacted that could adversely affect the liability structure that currently exists in the United States;
•
Uncertainties with respect to procurement of nuclear fuel and suppliers thereof, fabrication of nuclear fuel and related vendors, 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 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. Although we have no reason to anticipate a serious nuclear incident, 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, resulting in costly changes to units under construction or in operation and adversely impacting our results of operations, cash flows and financial condition. Furthermore, a major incident at a domestic nuclear facility could result in retrospective premium assessments under our nuclear insurance coverages.
Failure to retain and attract key personnel could adversely affect the Company’s and Consolidated SCE&G’s operations and financial performance.
As with many other utilities, a significant portion of our workforce will be eligible for retirement during the next few years. We must 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 businesses. 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. In particular, the timely hiring, training, licensing and retention of personnel needed for the operation of the New Units is necessary to maintain the schedule for their operation. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets including the New Units 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. Furthermore, increased medical benefit costs of employees and retirees could adversely affect the results of operations of the Company and Consolidated SCE&G. Medical costs in this country have risen significantly over the past number of years and are expected to continue to increase at unpredictable rates. Such increases, unless satisfactorily managed by the Company and Consolidated SCE&G, could adversely affect results of operations.
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 condition, 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 plants 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, including customers' concerns regarding rate increases, such as those periodic rate increases under the BLRA, may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously supported by legislation or approved by regulators), to the detriment of the Company or Consolidated SCE&G (e.g., revision or repeal of the BLRA). 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 condition, 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 related to compliance with laws and regulations, ethical conduct, operational effectiveness, customer service and the 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 assure reliability of provided services, to focus on the safety of employees, customers and the public, to ensure environmental compliance, 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. Traditional news media and social media can very rapidly convey information, whether factual or not, to large numbers of people, including customers, investors, regulators, legislators and other stakeholders, and the failure to effectively manage timely, accurate communication through these channels could adversely impact our reputation. The Company and Consolidated SCE&G also are committed to operational excellence, to quality customer service, 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, regulatory action, 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. Insurance may not be available or adequate to respond to these events.
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, which secures its First Mortgage Bonds, 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.
Electric Properties
The following table shows the electric generating facilities and their net generating capacity as of December 31, 2016.
Net Generating Capacity
In-Service
Summer
Date
(MW)
Coal-Fired Steam:
Wateree - Eastover, SC
Williams - Goose Creek, SC
Cope - Cope, SC
Kapstone - Charleston, SC
Gas-Fired Steam:
McMeekin - Irmo, SC
Urquhart Unit 3 - Beech Island, SC
Nuclear:
Summer Station Unit 1 - Parr, SC (reflects SCE&G's 66.7% ownership share)
Summer Station Unit 2 and Unit 3 - Parr, SC
*
Internal Combustion Turbines:
Jasper Combined Cycle - Jasper, SC
Urquhart Combined Cycle - Beech Island, SC
Peaking units - various locations in SC
1968-2010
Hydro:
Fairfield Pumped Storage - Parr, SC
Saluda - Irmo, SC
Other - various locations in or bordering SC
1905-1914
* SCE&G presently owns 55% of Unit 2 and Unit 3, which are being constructed at Summer Station.
SCE&G owns 433 substations having an aggregate transformer capacity of 31.5 million KVA. The transmission system consists of 3,442 miles of lines, and the distribution system consists of 18,522 pole miles of overhead lines and 7,441 trench miles of underground lines.
Natural Gas Distribution and Transmission Properties
SCE&G's natural gas system includes 447 miles of transmission pipeline of up to 20 inches in diameter that connect its distribution system with Southern Natural, Transco and DCGT. SCE&G’s distribution system consists of 17,375 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 6,180 MMBTU per day and store the liquefied equivalent of 1,009,400 MMBTU of natural gas. The Salley facility can store the liquefied equivalent of 927,000 MMBTU of natural gas and has no liquefying capabilities. The LNG facilities have the capacity to regasify approximately 61,800 MMBTU per day at Charleston and 92,700 MMBTU per day at Salley.
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 21,686 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000,000 MMBTU, the capacity to liquefy up to 4,000 MMBTU per day and the capacity to regasify approximately 100,000 MMBTU per day.
ITEM 3. LEGAL PROCEEDINGS
SCANA and SCE&G are subject to various 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. In addition, certain material regulatory and environmental matters and uncertainties, some of which remain outstanding at December 31, 2016, are described in the Rate Matters section of Note 2 and in the Environmental section of Note 10 to the consolidated financial statements.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable
EXECUTIVE OFFICERS OF SCANA CORPORATION
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 wholly-owned subsidiaries unless otherwise indicated.
Name
Age
Positions Held During Past Five Years
Dates
Kevin B. Marsh
Chairman of the Board and Chief Executive Officer
President and Chief Operating Officer-SCANA
*-present
*-present
Jimmy E. Addison
Executive Vice President-SCANA
Chief Financial Officer
President and Chief Operating Officer-SCANA Energy
*-present
*-present
2014-present
Jeffrey B. Archie
Senior Vice President and Chief Nuclear Officer-SCE&G
Senior Vice President-SCANA
*-present
*-present
Sarena D. Burch
Senior Vice President-Risk Management and Corporate Compliance Senior Vice President-Fuel Procurement and Asset Management-SCANA, SCE&G and PSNC Energy
2016-present
*-2015
Stephen A. Byrne
President-Generation and Transmission and Chief Operating Officer-SCE&G
Executive Vice President-SCANA
*-present
*-present
D. Russell Harris
President-Gas Operations-SCE&G
President and Chief Operating Officer-PSNC Energy
Senior Vice President-Gas Distribution-SCANA
Senior Vice President-SCANA
2013-present
*-present
2013-present
2012-2013
Kenneth R. Jackson
Senior Vice President-Economic Development, Governmental and Regulatory Affairs
Vice President-Rates and Regulatory Services
2014-present
*-2014
W. Keller Kissam
President-Retail Operations-SCE&G
Senior Vice President-SCANA
*-present
*-present
Ronald T. Lindsay
Senior Vice President, General Counsel and Assistant Secretary
*-present
Randal M. Senn
Senior Vice President-Administration-SCANA
Vice President and Chief Information Officer
Chief Information Officer
2016-present
*-2016
*Indicates positions held at least since February 24, 2012.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
SCANA:
Price Range (NYSE Composite Listing):
4th Qtr.
3rd Qtr.
2nd Qtr.
1st Qtr.
4th Qtr.
3rd Qtr.
2nd Qtr.
1st Qtr.
High
$
74.94
$
76.41
$
75.67
$
70.35
$
61.95
$
57.73
$
56.26
$
65.57
Low
$
67.31
$
69.04
$
66.02
$
59.46
$
54.84
$
50.17
$
47.77
$
52.03
SCANA common stock trades on the NYSE using the ticker symbol SCG. At February 20, 2017 there were 142,916,917 shares of SCANA common stock outstanding which were held by approximately 25,000 shareholders of record. For a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2016, see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
SCANA declared quarterly dividends on its common stock of $0.575 per share in 2016 and $0.545 per share in 2015. On February 16, 2017, SCANA increased the quarterly cash dividend rate on SCANA common stock to $0.6125 per share, an increase of approximately 6.5%. The next quarterly dividend is payable April 1, 2017 to shareholders of record on March 10, 2017. For a discussion of provisions that could limit the payment of cash dividends, see Financing Limits and Related Matters in the Liquidity and Capital Resources section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 3 to the consolidated financial statements.
The following table provides information about purchases by or on behalf of SCANA or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended (Exchange Act)) of shares or other units of any class of SCANA's equity securities that are registered pursuant to Section 12 of the Exchange Act:
Issuer Purchases of Equity Securities
(a)
(b)
(c)
(d)
Period
Total number of shares (or units) purchased
Average price paid
per share (or unit)
Total number of shares (or units) purchased as
part of publicly announced
plans or programs
Maximum number (or approximate dollar value) of shares (or units) that may yet be
purchased under the
plans or programs
October 1-31, 2016
7,583
$
69.29
7,583
November 1-30, 2016
-
-
-
December 1-31, 2016
-
-
-
Total
7,583
7,583
*
*The above table represents shares acquired for non-employee directors under the Director Compensation and Deferral Plan. On December 16, 2014, SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans. This program took effect in the first quarter of 2015 and has no stated maximum number of shares that may be purchased and no stated expiration date.
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 2016 and 2015, SCE&G declared quarterly dividends on its common stock in the following amounts:
Declaration Date
Amount
Declaration Date
Amount
February 18, 2016
$
72.2
million
February 20, 2015
$
69.0
million
April 28, 2016
73.3
million
April 30, 2015
67.8
million
July 28, 2016
74.0
million
July 30, 2015
68.4
million
October 27, 2016
77.5
million
October 29, 2015
72.3
million
On February 16, 2017, SCE&G declared a quarterly dividend on its common stock of $76.9 million.
For a discussion of provisions that could limit the payment of cash dividends, see Financing Limits and Related Matters in the Liquidity and Capital Resources section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 3 to the consolidated financial statements.
ITEM 6. SELECTED FINANCIAL DATA
As of or for the Year Ended December 31,
(Millions of dollars, except statistics and per share amounts)
SCANA:
Statement of Income Data
Operating Revenues
$
4,227
$
4,380
$
4,951
$
4,495
$
4,176
Operating Income
$
1,153
$
1,308
$
1,007
$
$
Net Income
$
$
$
$
$
Common Stock Data
Weighted Avg Common Shares Outstanding (Millions)
142.9
142.9
141.9
138.7
131.1
Basic Earnings Per Share
$
4.16
$
5.22
$
3.79
$
3.40
$
3.20
Diluted Earnings Per Share
$
4.16
$
5.22
$
3.79
$
3.39
$
3.15
Dividends Declared Per Share of Common Stock
$
2.30
$
2.18
$
2.10
$
2.03
$
1.98
Balance Sheet Data
Utility Plant, Net
$
14,324
$
13,145
$
12,232
$
11,643
$
10,896
Total Assets
$
18,707
$
17,146
$
16,818
$
15,127
$
14,568
Total Equity
$
5,725
$
5,443
$
4,987
$
4,664
$
4,154
Short-term and Long-term Debt
$
7,431
$
6,529
$
6,581
$
5,788
$
5,707
Other Statistics
Electric:
Customers (Year-End)
709,418
698,372
687,800
678,273
669,966
Total sales (Million kWh)
23,458
23,102
23,319
22,313
23,879
Generating capability-Net MW (Year-End)
5,233
5,234
5,237
5,237
5,533
Territorial peak demand-Net MW
4,807
4,970
4,853
4,574
4,761
Regulated Gas:
Customers, excluding transportation (Year-End)
906,883
881,295
859,186
837,232
818,983
Sales, excluding transportation (Thousand Therms)
890,113
875,218
973,907
921,533
798,978
Transportation customers (Year-End)
Transportation volumes (Thousand Therms)
674,999
791,402
1,786,897
1,729,399
1,559,542
For information on the impact of certain dispositions on SCANA's selected financial data, see Note 1 to the consolidated financial statements.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pursuant to General Instruction I of Form 10-K, SCE&G is permitted to omit certain information related to itself and its consolidated affiliates called for by Item 7 of Form 10-K, and instead provide a management’s narrative explanation of its consolidated results of operation and other information described therein. Such information is presented hereunder specifically for Consolidated SCE&G, but may be presented alongside information presented for the Company generally. Consolidated SCE&G makes no representation as to information relating solely to SCANA Corporation and its subsidiaries (other than Consolidated SCE&G).
OVERVIEW
SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina and in the purchase, transmission and sale of natural gas in North Carolina and South Carolina. Through a wholly-owned nonregulated subsidiary, SCANA markets natural gas to retail customers in Georgia and to wholesale customers in the southeast. A service company subsidiary of SCANA provides primarily administrative and management 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 amounts attributable to the Company’s regulated and nonregulated operations and other nonregulated (including the holding company and the services company).
Net Income
Regulated
%
%
%
Nonregulated operations
%
%
%
Other nonregulated
(3
)%
%
(5
)%
Assets
Regulated
%
%
%
Nonregulated operations
%
%
%
Other nonregulated
%
%
%
In the first quarter of 2015, SCANA closed on the sales of its interstate natural gas pipeline and telecommunications subsidiaries. Gains from these sales are included within Other. See Dispositions in Note 1 to the consolidated financial statements.
Key Earnings Drivers and Outlook
In 2016, companies announced plans to invest over $1.8 billion, with the expectation of creating approximately 7,000 jobs in the Company's South Carolina and North Carolina service territories. At December 31, 2016, South Carolina's unemployment rate was 4.3%, which is approximately 1.2% lower than the prior year. In addition, each of the Company's regulated businesses experienced positive customer growth year over year.
Over the next five years, key earnings drivers for the Company are expected to 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 and the level of growth of operation and maintenance, interest and other expenses and taxes.
Electric Operations
SCE&G's electric operations primarily generate electricity and provide for its transmission, distribution and sale to approximately 709,000 customers (as of December 31, 2016) in portions of South Carolina 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, provides financing for and sells at cost to SCE&G nuclear fuel, certain fossil fuels and emission and other environmental allowances.
Operating results are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control costs. 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 electricity prices and, therefore, the competitive position of electricity compared to other energy sources.
Embedded in the rates charged to customers is an allowed regulatory ROE. SCE&G’s allowed ROE in 2016 was 10.25% for non-BLRA rate base and 10.5% for BLRA-related rate base. For BLRA-related rate base existing prior to 2016, SCE&G's allowed ROE was 11.0%.
New Nuclear Construction
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of two 1,250 MW (1,117 MW, net) nuclear generation units, which SCE&G will jointly own with Santee Cooper. SCE&G's current ownership share in the New Units is 55%, and SCE&G has agreed to acquire an additional 5% ownership from Santee Cooper in increments beginning with the commercial operation date of Unit 2.
On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding certain disputes, and the EPC Contract was amended. The October 2015 Amendment became effective on December 31, 2015, and among other things, it resolved by settlement and release substantially all then-outstanding disputes between SCE&G and the Consortium. The October 2015 Amendment also provided SCE&G and Santee Cooper an option, subject to regulatory approvals, to fix the
total amount to be paid to the Consortium for its entire scope of work on the project after June 30, 2015, subject to certain exceptions. In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units developed as a result of the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G’s election of the fixed price option.
The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively, although recent communications from WEC indicate substantial completion dates of April 2020 and December 2020 for Units 2 and 3, respectively. These later dates remain within SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits. However, there is substantial uncertainty as to WEC’s ability to meet these dates given its historical inability to meet forecasted productivity and work force efficiency levels.
The approved capital cost schedule includes incremental capital costs. SCE&G’s total project capital cost is now estimated at approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25%. This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time.
SCE&G and Santee Cooper, the co-owner of the New Units, continue to evaluate various actions which might be taken in the event that Toshiba and WEC are unable or unwilling to complete the project. These include completing the work under any of several arrangements with other contractors or, were it determined to be prudent, halting the project, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA. Any significant delay in the timing of construction or any determination by the SCPSC to disallow the recovery of costs would adversely impact results of operations, cash flows and financial condition.
The information summarized above, as well as additional information regarding uncertainties concerning WEC’s ability to continue to fulfill its performance and financial commitments and Toshiba's ability to perform under its payment guaranty with respect to the project and other related matters, is further discussed in Note 2 and Note 10 to the consolidated financial statements.
Environmental
The results of recent elections may affect the pace at which federal environmental laws and regulations are enacted or how stringently their provisions are interpreted in the future. However, public sentiment surrounding air quality and water quality remains strong and is expected to continue unabated.
Over several years, SCE&G has made significant investments in constructing non-emitting generation (the New Units previously mentioned) and retiring certain coal-fired plants or converting them to burn natural gas. In addition, SCE&G expects to add the renewable energy from six new solar generating facilities at locations throughout its electric service territory over the next few years. The impact of these investments is expected to result in a significant shift toward non-emitting sources of fuel used to generate electricity in the future.
Generation Type
2016 Actual
2021 Projected
Nuclear
24.7%
56.7%
Hydro
3.3%
3.4%
Solar
-%
2.2%
Total Non-emitting
28.0%
62.3%
Biomass
1.7%
-%
Natural Gas
33.5%
17.9%
Coal
36.8%
19.8%
Total Generation
100.0%
100.0%
In addition, SCE&G and GENCO have made significant investments to install pollution control equipment at their remaining coal-fired plants. These investments, together with investments in non-emitting generation, have reduced their air emissions and are expected to result in additional reductions in the future.
Emissions, measured in thousands of tons
Year
NOX
SO2
CO2
27.0
107.9
18,778.7
7.0
19.3
12,507.9
7.6
16.8
13,984.6
5.7
5.1
12,891.8
5.4
2.7
11,567.4
2021*
3.2
1.2
7,062.5
% decrease from 2005 to 2021*
88.1
%
98.9
%
62.4
%
* Projected
The status of significant environmental laws and regulations and certain initiatives undertaken to ensure compliance with them are described in Environmental Matters herein and in Note 10 to the consolidated financial statements. In addition, uncertainties with respect to the New Units are described in Note 10 to the consolidated financial statements.
Gas Distribution
The local distribution operations of SCE&G and PSNC Energy purchase, transport and sell natural gas to approximately 907,000 retail customers (as of December 31, 2016) in portions of South Carolina and North Carolina in areas covering approximately 35,000 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 costs. Embedded in the rates charged to customers is an allowed regulatory ROE for SCE&G of 10.25% and for PSNC Energy of 10.60% through October 31, 2016 and 9.7% thereafter.
Demand for natural gas is primarily affected by weather, customer growth, the economy and 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 will impact the Company’s ability to retain large commercial and industrial customers.
The production of shale gas in the United States continues to keep prices for this commodity at historic lows, and such prices are expected to continue at generally low levels for several years. The supply of natural gas from the Marcellus shale basin has prompted companies unaffiliated with SCANA to propose a 550-mile pipeline that would bring natural gas from West Virginia to Virginia and North Carolina. This pipeline is expected to be completed in late 2019 and, if successful, it may drive economic development along its path, including areas within PSNC Energy's service territory, and may serve to assist in keeping natural gas competitively priced in the region.
Gas Marketing
SCANA Energy markets natural gas in the southeast and provides energy-related services to customers, including, notably, retail customers in Georgia. Operating results for energy marketing are influenced by customer demand for natural gas and the ability to control costs. The price of alternate fuels and customer growth significantly affect demand for natural gas. In addition, the availability of certain pipeline capacity to serve industrial and other customers is dependent upon the market share held by SCANA Energy in the Georgia retail market. SCANA Energy sells natural gas to approximately 450,000 customers (as of December 31, 2016) throughout Georgia. This market is mature, resulting in lower margins and stiff competition. Competitors include affiliates of large energy companies as well as electric membership cooperatives, among others. SCANA Energy’s ability to maintain its market share primarily depends on the prices it charges customers relative to the prices charged by its competitors and its ability to provide high levels of customer service. In addition, SCANA Energy's operating results are sensitive to weather.
RESULTS OF OPERATIONS
Earnings and Dividends
Earnings and dividends were as follows:
The Company
Earnings per share
$
4.16
$
5.22
$
3.79
Cash dividends declared per share
$
2.30
$
2.18
$
2.10
Consolidated SCE&G
Net income (millions of dollars)
$
525.8
$
479.5
$
457.7
On February 16, 2017, SCANA declared a quarterly cash dividend on its common stock of $0.6125 per share.
2016 vs 2015
Earnings per share decreased primarily due to the sales of CGT and SCI in 2015, higher operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest expense. These decreases were partially offset by higher electric and gas distribution margins, higher other income net of other expenses and higher energy marketing net income, as further described below.
Consolidated SCE&G's net income increased primarily due to higher electric and gas distribution margins, partially offset by higher operation and maintenance expense, higher depreciation expense, higher property taxes, higher interest cost, and higher income taxes, as further described below.
2015 vs 2014
Earnings per share increased due to the sales of CGT and SCI in 2015, higher electric margins, lower operation and maintenance expenses and lower depreciation expense. These increases were partially offset by lower gas margins, higher property taxes, lower other income, higher interest expense, a higher effective tax rate and dilution from additional shares outstanding, as further described below.
The sales of CGT and SCI were closed in the first quarter of 2015. These subsidiaries operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. Therefore, CGT and SCI were not a part of the Company's core business. See Note 12 to the consolidated financial statements.
Consolidated SCE&G's net income increased primarily due to higher electric and gas distribution margins and lower depreciation expense, partially offset by lower other income, higher operation and maintenance expense, higher property taxes, higher interest cost, and higher income taxes, as further described below.
Electric Operations
Electric Operations for the Company and for Consolidated SCE&G is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric Operations operating income (including transactions with affiliates) was as follows:
The Company
Consolidated SCE&G
Millions of dollars
Operating revenues
$
2,619.4
$
2,557.1
$
2,629.4
$
2,619.4
$
2,557.1
$
2,629.4
Fuel used in electric generation
576.1
660.6
799.3
576.1
660.6
799.3
Purchased power
63.7
52.1
80.7
63.7
52.1
80.7
Margin
1,979.6
1,844.4
1,749.4
1,979.6
1,844.4
1,749.4
Other operation and maintenance
526.1
497.1
494.8
540.2
509.6
507.5
Depreciation and amortization
286.5
277.3
300.3
274.9
266.9
289.5
Other taxes
210.4
194.5
186.7
207.9
192.4
184.8
Operating Income
$
956.6
$
875.5
$
767.6
$
956.6
$
875.5
$
767.6
Electric operations can be significantly impacted by the effects of weather. SCE&G estimates the effects on its electric business of actual temperatures in its service territory as compared to historical averages to develop an estimate of electric margin revenue attributable to the effects of abnormal weather. Results in 2016 reflect warmer than normal weather in the second and third quarters and milder than normal weather in the first and fourth quarters. Results in 2015 reflect colder than normal weather in the first quarter, warmer than normal weather in the second and third quarters and milder than normal weather in the fourth quarter. Results in 2014 reflect colder than normal weather in the first quarter, hotter than normal weather in the second and third quarters and milder than normal weather in the fourth quarter.
2016 vs 2015
•
Margin increased due to base rate increases under the BLRA of $60.7 million, the effects of weather of $22.1 million, residential and commercial customer growth of $22.1 million, higher industrial margin of $7.6 million and higher collections under the rate rider for pension costs of $13.5 million. These margin increases were partially offset by lower residential and commercial average use. The higher pension rider collections had no effect on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs. Margin also increased due to downward revenue adjustments in 2015, pursuant to orders from the SCPSC, to apply $14.5 million as an offset to fuel cost recovery upon the adoption of new (lower) electric depreciation rates and by $5.2 million related to DSM Programs. These adjustments had no effect on net income in 2015 as they were fully offset by the recognition of $14.5 million of lower depreciation expense and by the recognition, within other income, of $5.2 million of gains realized upon the settlement of certain interest rate contracts.
•
Other operation and maintenance expenses increased due to higher labor costs of $25.4 million, primarily due to increased pension cost associated with the higher pension rider collections and higher incentive compensation costs. Other operation and maintenance expenses also increased due to higher amortization of DSM program costs of $2.0 million.
•
Depreciation and amortization increased primarily due to net plant additions.
•
Other taxes increased primarily due to higher property taxes on net plant additions.
2015 vs 2014
•
Margin increased due to downward adjustments of $69.0 million in 2014, compared to downward adjustments of $19.7 million in 2015, pursuant to orders of the SCPSC, related to fuel cost recovery and DSM Programs. These adjustments had no effect on net income as they were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain derivative interest rate contracts, lower depreciation expense upon the adoption and implementation of revised depreciation rates as a result of an updated depreciation study and the application, as a reduction to operation and maintenance expenses, of a portion of the storm damage reserve. Margin also increased due to base rate increases under the BLRA of $65.7 million and residential and commercial customer growth of $21.4 million. These increases were partially offset by $25.6 million due to the effects of weather, lower industrial margins of $14.6 million primarily due to variable price contracts, and lower collections under the rate rider for pension costs of $3.0 million. See Note 2 to the consolidated financial statements.
•
Other operation and maintenance expenses increased due to the application of $5.0 million in 2014 of the storm damage reserve to offset downward revenue adjustments related to DSM Programs and the amortization of $3.7 million of DSM Programs cost. These increases were partially offset by lower labor costs of $2.0 million primarily due to lower pension cost recognition as a result of lower rate rider collections.
•
Depreciation and amortization decreased by $28.7 million in 2015 due to the implementation of the above mentioned revised depreciation rates, $14.5 million of which was offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions.
•
Other taxes increased due primarily to higher property taxes associated with net plant additions.
Sales volumes (in GWh) related to the electric operations margin above, by class, were as follows:
Classification
Residential
8,140
7,978
8,156
Commercial
7,506
7,386
7,371
Industrial
6,265
6,201
6,234
Other
Total retail sales
22,511
22,160
22,361
Wholesale
Total Sales
23,458
23,102
23,319
2016 vs 2015
Retail sales volumes increased primarily due to the effects of weather and customer growth.
2015 vs 2014
Retail sales volumes decreased primarily due to the effects of weather, partially offset by customer growth.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G, and for the Company, also includes PSNC Energy. Gas Distribution operating income (including transactions with affiliates) was as follows:
The Company
Consolidated SCE&G
Millions of dollars
Operating revenues
$
789.8
$
811.7
$
1,014.0
$
366.8
$
372.7
$
462.2
Gas purchased for resale
345.9
383.7
592.5
182.9
192.5
283.1
Margin
443.9
428.0
421.5
183.9
180.2
179.1
Other operation and maintenance
172.7
161.4
154.8
73.6
69.8
67.7
Depreciation and amortization
82.0
77.5
72.4
27.3
26.8
25.7
Other taxes
41.5
37.5
34.8
26.8
24.9
23.1
Operating Income
$
147.7
$
151.6
$
159.5
$
56.2
$
58.7
$
62.6
The effect of abnormal weather conditions on gas distribution margin is mitigated by the WNA at SCE&G and the CUT at PSNC Energy as further described in Revenue Recognition in Note 1 of the consolidated financial statements. The WNA and CUT affect margins but not sales volumes.
2016 vs 2015
•
Margin increased $11.5 million at the Company, including $6.0 million at SCE&G, due to residential and commercial customer growth, $5.0 million due to an NCUC-approved rate increase effective November 2016 at PSNC Energy, and $1.1 million due to an SCPSC-approved increase in base rates under the RSA effective November 2016 at SCE&G. These increases were partially offset by lower average use of $4.1 million at SCE&G.
•
Other operation and maintenance expenses increased due to higher labor costs of $6.7 million at the Company, including $2.1 million at SCE&G, due primarily to higher incentive compensation costs.
•
Depreciation and amortization increased at the Company and SCE&G due to net plant additions, partially offset by the implementation of SCPSC-approved revised (lower) depreciation rates at SCE&G of $1.1 million.
•
Other taxes increased at the Company and SCE&G due to net plant additions.
2015 vs 2014
•
Margin increased due to residential and commercial customer growth of $7.8 million at the Company, including $4.3 million at SCE&G, partially offset by a decrease of $3.1 million due to an SCPSC-approved decrease in base rates at SCE&G under the RSA effective November 2014.
•
Other operation and maintenance expenses increased at the Company and SCE&G due to higher labor costs, primarily due to incentive compensation.
•
Depreciation and amortization increased at the Company and SCE&G due to net plant additions.
•
Other taxes increased at the Company and SCE&G due primarily to higher property taxes associated with net plant additions.
Sales volumes (in MMBTU) related to gas distribution margin by class, including transportation, were as follows:
The Company
Consolidated SCE&G
Classification (in thousands)
Residential
40,142
39,090
46,207
12,420
12,086
14,917
Commercial
29,078
28,064
30,701
12,879
12,580
13,936
Industrial
19,364
20,101
20,343
17,228
17,901
18,307
Transportation gas
49,769
49,297
45,506
5,250
4,781
4,286
Total
138,353
136,552
142,757
47,777
47,348
51,446
2016 vs 2015
Residential and commercial firm sales volumes increased primarily due to customer growth. Commercial and industrial interruptible volumes decreased, and firm volumes increased, due to customers switching from interruptible to firm service at SCE&G. Industrial volumes decreased and transportation volumes increased due to customers switching to transportation only service.
2015 vs 2014
Residential and commercial firm sales volumes decreased due to the effects of weather and lower average use, partially offset by customer growth. Commercial and industrial interruptible volumes decreased due to a shift to transportation service from system supply and the impact of curtailments, partially offset at the Company by lower curtailments at PSNC Energy. Transportation volumes increased due to customers shifting to transportation-only service at SCE&G, and at the Company, included increased sales for natural gas fired electric generation in PSNC Energy's territory.
Gas Marketing
Gas Marketing is comprised of the Company’s nonregulated marketing operation, SCANA Energy, which operates in the southeast and includes Georgia’s retail natural gas market. Gas Marketing operating revenues and net income were as follows:
Millions of dollars
Operating revenues
$
936.7
$
1,146.7
$
1,496.4
Net Income
29.8
27.6
31.0
2016 vs 2015
Operating revenues decreased due to the lower market price of natural gas and lower industrial sales volume. Net income increased primarily due to a weather-related increase in demand.
2015 vs 2014
Operating revenues decreased due to the lower market price of natural gas, weather-related changes in demand, lower industrial sales volume and lower market prices. Net income decreased primarily due to weather-related changes in demand, partially offset by lower cost of gas and lower costs of transportation to serve customers.
Other Operating Expenses
Other operating expenses were as follows:
The Company
Consolidated SCE&G
Millions of dollars
Other operation and maintenance
$
755.6
$
715.3
$
728.3
$
613.8
$
579.4
$
575.2
Depreciation and amortization
370.9
357.5
383.7
302.2
293.7
315.2
Other taxes
253.9
234.2
228.8
234.7
217.3
207.9
Changes in other operating expenses are largely attributable to the electric operations and gas distribution segments and are addressed in those discussions. Additional information is provided below.
2016 vs 2015
In addition to factors discussed in the electric operations and gas distribution segments, overall increases in other operating expenses were partially offset by the Company's sale of CGT in early 2015, which resulted in decreases in other operation and maintenance expenses of $2.2 million, depreciation and amortization of $0.7 million and other taxes of $0.5 million.
2015 vs 2014
In addition to factors discussed in the electric operations and gas distribution segments, the Company's sale of CGT in early 2015 resulted in decreases in other operation and maintenance expenses of $24.2 million, depreciation and amortization of $7.8 million and other taxes of $8 million.
Net Periodic Benefit Cost
Other operation and maintenance expense includes net periodic benefit cost, which was recorded on the income statements and balance sheets as follows:
The Company
Consolidated SCE&G
Millions of dollars
Income Statement Impact:
Employee benefit costs
$
19.2
$
5.3
$
5.0
$
16.4
$
2.8
$
4.0
Other expense
0.9
1.1
0.2
0.2
0.2
0.1
Balance Sheet Impact:
Increase in capital expenditures
5.3
3.9
0.5
4.7
3.4
0.3
Component of amount receivable from Summer Station co-owner
2.1
1.5
0.1
2.1
1.5
0.1
Increase (decrease) in regulatory assets
(4.6
)
6.2
(3.2
)
(4.6
)
6.2
(3.2
)
Net periodic benefit cost
$
22.9
$
18.0
$
2.6
$
18.8
$
14.1
$
1.3
Pursuant to regulatory orders, SCE&G recovers current pension expense through a rate rider (for retail electric operations) and through cost of service rates (for gas operations), and amortizes pension costs previously deferred in regulatory assets as further described in Note 2 and Note 8 to the consolidated financial statements. Amounts amortized were $2.0 million for retail electric operations and $1.0 million for gas operations for each period presented.
Other Income (Expense)
Other income (expense) includes the results of certain incidental non-utility activities of regulated subsidiaries, the activities of certain of the Company's non-regulated subsidiaries, and 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. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits), both of which have the effect of increasing reported net income. Components of other income (expense) and AFC were as follows:
The Company
Consolidated SCE&G
Millions of dollars
Other income
$
64.4
$
74.5
$
121.8
$
29.3
$
31.1
$
79.8
Other expense
(38.5
)
(60.1
)
(64.3
)
(24.1
)
(31.1
)
(33.8
)
Gain on sale of SCI, net of transaction costs
-
106.6
-
-
-
-
AFC - equity funds
29.4
27.0
32.7
26.1
24.8
27.7
2016 vs 2015
Other income at the Company and Consolidated SCE&G decreased by $3.5 million due to lower gains on the sale of land and due to the recognition in 2015 of $5.2 million of gains realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion). At the Company, other income also decreased by $3.9 million and other expenses decreased by $2.3 million due to the sale of SCI, and other income and other expenses decreased by $10.5 million for billings to DCGT for transition services provided at cost pursuant to the terms of the sale of CGT. Other expenses at the Company and Consolidated SCE&G decreased by $5.2 million due to lower contribution expenses. In 2015, the Company's other income included the gain on the sale of SCI (see Dispositions in Note 1 to the consolidated financial statements). AFC increased due to construction activity.
2015 vs 2014
Other income decreased at the Company and Consolidated SCE&G due primarily to the recognition of $64.0 million of gains in 2014, compared to $5.2 million in 2015, realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to the SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion). At the Company, other income also decreased by $18.3 million and other expenses decreased by $10.9 million due to the sale of SCI, and other income and other expenses increased by $12.7 million for billings to DCGT for transition services provided at cost pursuant to the terms of the sale of CGT. In 2015, the Company's other income included the gain on the sale of SCI (see Dispositions in Note 1 to the consolidated financial statements). AFC decreased due to lower AFC rates.
Interest Expense
Components of interest expense, net of the debt component of AFC, were as follows:
The Company
Consolidated SCE&G
Millions of dollars
Interest on long-term debt, net
$
330.3
$
311.3
$
306.7
$
253.8
$
236.0
$
217.6
Other interest expense
12.0
6.5
5.7
16.2
12.1
10.4
Total
$
342.3
$
317.8
$
312.4
$
270.0
$
248.1
$
228.0
Interest expense increased in each year primarily due to increased borrowings.
Income Taxes
At the Company, income tax expense decreased from 2015 to 2016 primarily due to lower income before taxes. Income tax expense increased from 2014 to 2015 primarily due to higher income before taxes. Income before taxes, income taxes and the effective tax rate were all higher in 2015 primarily due to the sales of CGT and SCI. At Consolidated SCE&G, income tax expense increased each year primarily due to increases in income before taxes.
LIQUIDITY AND CAPITAL RESOURCES
The Company expects to meet contractual cash obligations in 2017 through internally generated funds and additional short- and long-term borrowings. The Company may also meet such obligations through the sale of equity securities. The Company expects that, barring a future impairment of the capital markets or its access to such markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt.
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 regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.
Due primarily to the availability of proceeds from the sale of two subsidiaries in the first quarter of 2015, the Company began using open market purchases for its stock plans at the end of January 2015. Prior to the use of open market purchases, SCANA common stock was acquired on behalf of participants in SCANA’s Investor Plus Plan and Stock Purchase-Savings Plan through the original issuance of shares. This provided additional equity of approximately $14 million in 2015.
Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including regulatory environment, capital structure and the ability to meet liquidity requirements. Changes in the regulatory environment or deterioration of the Company’s or its rated operating companies' commonly monitored financial credit metrics and adverse developments with respect to nuclear construction could negatively affect the Company’s debt ratings. This could cause the Company to pay higher interest rates on its long- and short-term indebtedness, and could limit the Company's access to capital markets and liquidity.
Cash provided from operating activities in 2015 reflects lower tax payments arising from Congress’ extension of bonus deprecation provisions in 2014. Cash provided from operating activities in 2016 reflects significant tax benefits (reductions in income tax payments) arising from the deduction under Section 174 of the IRC of certain expenditures related to the design and construction of the New Units and the related claim of credits under Section 41 of the IRC. Similar tax benefits are expected to be claimed in the next several years as design and construction continues, and these cash flows are expected to continue to supplant portions of financing which would otherwise be obtained in the capital markets.
Capital Expenditures
Cash outlays for property additions and construction expenditures, including nuclear fuel, were $1.6 billion in 2016. Estimates of capital expenditures for construction and nuclear fuel for the next three years, which are subject to continuing review and adjustment, are as follows:
Estimated Capital Expenditures
Millions of dollars
SCE&G - Normal
Generation
$
$
$
Transmission & Distribution
Other
Gas
Common
Total SCE&G - Normal
PSNC Energy
Other
Total Normal
New Nuclear (including transmission) - SCE&G*
1,222
1,165
Cash Requirements for Construction*
1,991
1,861
1,177
Nuclear Fuel - SCE&G
Total Estimated Capital Expenditures*
$
2,071
$
1,950
$
1,288
*Excludes the impact of the updated integrated project schedule which reflects WEC’s revised estimated completion dates of April 2020 and December 2020 for Units 2 and 3, respectively. See Note 10 to the consolidated financial statements.
Contractual cash obligations as of December 31, 2016 are summarized as follows:
Contractual Cash Obligations
Payments due by periods
Millions of dollars
Total
Less than
1 year
1 - 3 years
4 - 5 years
More than
5 years
Long- and short-term debt, including interest
$
13,976
$
1,292
$
2,002
$
1,257
$
9,425
Capital leases
Operating leases
Purchase obligations
3,869
2,387
1,481
-
Other commercial commitments
3,639
1,532
Total
$
21,626
$
4,613
$
5,088
$
1,879
$
10,046
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. SCE&G expects to be a joint owner and share operating costs and generation output of the New Units, with SCE&G currently responsible for 55 percent. SCE&G has agreed to acquire an additional 5% ownership in the New Units and has included $850 million for this purpose in other commercial commitments. See also New Nuclear Construction in Note 10 to the consolidated financial statements.
Purchase obligations include 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. Such forward contracts include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. 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.
Unrecognized tax benefits of approximately $219 million have been excluded from the table above due to uncertainty as to the timing of future payments. For additional information, see Note 5 to the consolidated financial statements.
In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no significant contributions are anticipated for the foreseeable future. Cash payments under the postretirement health care and life insurance benefit plan were $11.1 million in 2016, and such annual payments are expected to be the same or increase to as much as $15.9 million in the future.
The Company is party to certain NYMEX natural gas futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. The Company, including Consolidated SCE&G, is also party to certain interest rate derivative contracts for which unfavorable market movements above certain thresholds are funded in cash collateral. Certain of these interest rate derivative contracts are accounted for as cash flow hedges, and others are not designated as cash flow hedges but are accounted for pursuant to regulatory orders. See further discussion at
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments described in this section are held for purposes other than trading.
Interest Rate Risk
The tables below provide information about long-term debt issued by the Company and Consolidated SCE&G and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average interest rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.
The Company
December 31, 2016
Expected Maturity Date
Millions of dollars
Thereafter
Total
Fair Value
Long-Term Debt:
Fixed Rate ($)
12.5
721.7
11.1
360.2
489.0
4,789.7
6,384.3
7,040.6
Average Fixed Interest Rate (%)
4.21
6.01
4.40
6.33
4.64
5.73
5.70
-
Variable Rate ($)
4.4
4.4
4.4
4.4
4.4
125.0
147.0
142.7
Average Variable Interest Rate (%)
1.63
1.63
1.63
1.63
1.63
1.16
1.23
-
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)
554.4
704.4
4.4
4.4
4.4
128.6
1,400.6
12.3
Average Pay Interest Rate (%)
2.91
2.22
6.17
6.17
6.17
4.57
2.74
-
Average Receive Interest Rate (%)
1.00
1.00
1.63
1.63
1.63
1.08
1.02
-
December 31, 2015
Expected Maturity Date
Millions of dollars
Thereafter
Total
Fair Value
Long-Term Debt:
Fixed Rate ($)
111.5
10.6
719.8
9.1
358.3
4,673.0
5,882.3
6,336.2
Average Fixed Interest Rate (%)
1.16
4.42
6.02
4.73
6.35
5.63
5.63
-
Variable Rate ($)
4.4
4.4
4.4
4.4
4.4
129.4
151.4
145.5
Average Variable Interest Rate (%)
1.11
1.11
1.11
1.11
1.11
0.55
0.63
-
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)
654.4
554.4
4.4
4.4
4.4
133.0
1,355.0
(72.1
)
Average Pay Interest Rate (%)
2.89
2.91
6.17
6.17
6.17
4.62
3.10
-
Average Receive Interest Rate (%)
0.62
0.62
1.11
1.11
1.11
0.52
0.61
-
Consolidated SCE&G
December 31, 2016
Expected Maturity Date
Millions of dollars
Thereafter
Total
Fair Value
Long-Term Debt:
Fixed Rate ($)
12.0
721.7
11.1
10.2
39.0
4,339.7
5,133.7
5,687.3
Average Fixed Interest Rate (%)
4.27
6.01
4.40
4.54
3.60
5.75
5.76
-
Variable Rate ($)
-
-
-
-
-
67.8
67.8
64.9
Average Variable Interest Rate (%)
-
-
-
-
-
0.76
0.76
-
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)
550.0
700.0
-
-
-
71.4
1,321.4
31.7
Average Pay Interest Rate (%)
2.88
2.19
-
-
-
3.29
2.54
-
Average Receive Interest Rate (%)
1.00
1.00
-
-
-
0.64
0.98
-
December 31, 2015
Expected Maturity Date
Millions of dollars
Thereafter
Total
Fair Value
Long-Term Debt:
Fixed Rate ($)
110.4
10.1
719.8
9.1
8.3
3,873.0
4,730.7
5,095.0
Average Fixed Interest Rate (%)
1.13
4.50
6.02
4.73
4.94
5.71
5.64
-
Variable Rate ($)
-
-
-
-
-
67.8
67.8
63.7
Average Variable Interest Rate (%)
-
-
-
-
-
0.03
0.03
-
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)
650.0
550.0
-
-
-
71.4
1,271.4
(49.8
)
Average Pay Interest Rate (%)
2.87
2.88
-
-
-
3.28
2.90
-
Average Receive Interest Rate (%)
0.61
0.61
-
-
-
0.01
0.58
-
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.
For further discussion of long-term debt and interest rate derivatives, see the Liquidity and Capital Resources section in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 4 and 6 to the consolidated financial statements.
Commodity Price Risk
The following table provides information about the Company’s financial instruments, which are limited to financial positions of Energy Marketing and PSNC Energy, that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 MMBTU. Fair value represents quoted market prices.
Expected Maturity
Futures - Long
Settlement Price (a)
3.65
3.43
-
Contract Amount (b)
92.6
15.4
-
Fair Value (b)
102.3
16.5
-
Futures - Short
Settlement Price (a)
3.65
3.43
-
Contract Amount (b)
49.7
8.0
-
Fair Value (b)
51.6
8.3
-
Options - Purchased Call (Long)
Strike Price (a)
1.95
-
-
Contract Amount (b)
13.7
-
-
Fair Value (b)
2.6
-
-
Swaps - Commodity
Pay fixed/receive variable (b)
13.9
8.0
1.0
Average pay rate (a)
3.4075
3.4326
2.9667
Average received rate (a)
3.6240
3.2042
3.0954
Fair Value (b)
14.8
7.5
1.1
Pay variable/receive fixed (b)
30.4
11.3
0.8
Average pay rate (a)
3.6234
3.2431
3.1277
Average received rate (a)
3.2387
3.3488
2.9851
Fair Value (b)
27.1
11.7
0.8
Swaps - Basis
Pay variable/receive variable (b)
1.5
0.8
0.3
Average pay rate (a)
3.7218
3.4697
3.1904
Average received rate (a)
3.6529
3.4218
3.1234
Fair Value (b)
1.5
0.8
0.3
(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.
PSNC Energy utilizes futures, options and swaps to hedge gas purchasing activities. PSNC Energy’s tariffs 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, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash flows, and changes in common equity for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and the 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, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 24, 2017
SCANA Corporation and Subsidiaries
Consolidated Balance Sheets
December 31, (Millions of dollars)
Assets
Utility Plant In Service
$
13,444
$
12,883
Accumulated Depreciation and Amortization
(4,446
)
(4,307
)
Construction Work in Progress
4,845
4,051
Nuclear Fuel, Net of Accumulated Amortization
Goodwill
Utility Plant, Net
14,324
13,145
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $138 and $124
Assets held in trust, net-nuclear decommissioning
Other investments
Nonutility Property and Investments, Net
Current Assets:
Cash and cash equivalents
Receivables:
Customer, net of allowance for uncollectible accounts of $6 and $5
Income taxes
-
Other
Inventories:
Fuel
Materials and supplies
Prepayments
Other current assets
Total Current Assets
1,506
1,378
Deferred Debits and Other Assets:
Regulatory assets
2,130
1,937
Other
Total Deferred Debits and Other Assets
2,402
2,157
Total
$
18,707
$
17,146
See Notes to Consolidated Financial Statements.
December 31, (Millions of dollars)
Capitalization and Liabilities
Common Stock - no par value, 142.9 million shares outstanding for all periods presented
$
2,390
$
2,390
Retained Earnings
3,384
3,118
Accumulated Other Comprehensive Loss
(49
)
(65
)
Total Common Equity
5,725
5,443
Long-Term Debt, Net
6,473
5,882
Total Capitalization
12,198
11,325
Current Liabilities:
Short-term borrowings
Current portion of long-term debt
Accounts payable
Customer deposits and customer prepayments
Taxes accrued
Interest accrued
Dividends declared
Derivative financial instruments
Other
Total Current Liabilities
2,065
1,952
Deferred Credits and Other Liabilities:
Deferred income taxes, net
2,159
1,907
Asset retirement obligations
Pension and postretirement benefits
Unrecognized tax benefits
Regulatory liabilities
Other
Total Deferred Credits and Other Liabilities
4,444
3,869
Commitments and Contingencies (Note 10)
-
-
Total
$
18,707
$
17,146
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Income
Years Ended December 31, (Millions of dollars, except per share amounts)
Operating Revenues:
Electric
$
2,614
$
2,551
$
2,622
Gas-regulated
1,028
Gas-nonregulated
1,018
1,301
Total Operating Revenues
4,227
4,380
4,951
Operating Expenses:
Fuel used in electric generation
Purchased power
Gas purchased for resale
1,054
1,287
1,729
Other operation and maintenance
Depreciation and amortization
Other taxes
Total Operating Expenses
3,074
3,306
3,944
Gain on sale of CGT, net of transaction costs
-
-
Operating Income
1,153
1,308
1,007
Other Income (Expense):
Other income
Other expense
(38
)
(60
)
(64
)
Gain on sale of SCI, net of transaction costs
-
-
Interest charges, net of allowance for borrowed funds used during construction of $19, $15 and $16
(342
)
(318
)
(312
)
Allowance for equity funds used during construction
Total Other Expense
(287
)
(169
)
(221
)
Income Before Income Tax Expense
1,139
Income Tax Expense
Net Income
$
$
$
Earnings Per Share of Common Stock
$
4.16
$
5.22
$
3.79
Weighted Average Common Shares Outstanding (millions)
142.9
142.9
141.9
Dividends Declared Per Share of Common Stock
$
2.30
$
2.18
$
2.10
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Comprehensive Income
Years Ended December 31, (Millions of dollars)
Net Income
$
$
$
Other Comprehensive Income (Loss), net of tax:
Unrealized Losses on Cash Flow Hedging Activities:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $2, $(7) and $(9)
(12
)
(14
)
Cash flow hedging activities reclassified to interest expense, net of tax of $4, $4 and $4
Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $4, $9 and $(2)
(4
)
Net unrealized gains (losses) on cash flow hedging activities
(11
)
Deferred Costs of Employee Benefit Plans:
Deferred costs of employee benefit plans, net of tax of $-, $- and $(3)
-
-
(5
)
Amortization of deferred employee benefit plan costs reclassified to net income (see Note 8), net of tax of $-, $- and $-
(1
)
-
Net deferred costs of employee benefit plans
(1
)
-
(4
)
Other Comprehensive Income (Loss)
(15
)
Total Comprehensive Income
$
$
$
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Cash Flows
For the Years Ended December 31, (Millions of dollars)
Cash Flows From Operating Activities:
Net Income
$
$
$
Adjustments to reconcile net income to net cash provided from operating activities:
Gain on sale of subsidiaries
-
(355
)
-
Deferred income taxes, net
(31
)
Depreciation and amortization
Amortization of nuclear fuel
Allowance for equity funds used during construction
(29
)
(27
)
(33
)
Carrying cost recovery
(17
)
(12
)
(9
)
Changes in certain assets and liabilities:
Receivables
(112
)
(33
)
Income tax receivable
(142
)
-
-
Inventories
(43
)
(16
)
(62
)
Prepayments
(235
)
Regulatory assets
(114
)
(31
)
(138
)
Regulatory liabilities
(2
)
(1
)
(104
)
Accounts payable
(78
)
Unrecognized tax benefits
Taxes accrued
(41
)
(24
)
Pension and other postretirement benefits
(6
)
Derivative financial instruments
(9
)
(9
)
Other assets
(44
)
(3
)
(35
)
Other liabilities
(23
)
(15
)
Net Cash Provided From Operating Activities
1,092
1,059
Cash Flows From Investing Activities:
Property additions and construction expenditures
(1,579
)
(1,153
)
(1,092
)
Proceeds from sale of subsidiaries
-
-
Proceeds from investments (including derivative collateral returned)
1,117
Purchase of investments (including derivative collateral posted)
(788
)
(1,018
)
(475
)
Payments upon interest rate derivative contract settlement
(113
)
(263
)
(95
)
Proceeds from interest rate derivative contract settlement
-
-
Net Cash Used For Investing Activities
(1,620
)
(660
)
(1,315
)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock
-
Proceeds from issuance of long-term debt
Repayments of long-term debt
(117
)
(166
)
(54
)
Dividends
(325
)
(309
)
(294
)
Short-term borrowings, net
(387
)
Deferred financing costs
-
(3
)
-
Net Cash Provided From (Used For) Financing Activities
(360
)
Net Increase in Cash and Cash Equivalents
Cash and Cash Equivalents, January 1
Cash and Cash Equivalents, December 31
$
$
$
Supplemental Cash Flow Information:
Cash for-Interest paid (net of capitalized interest of $19, $15 and $16)
$
$
$
-Income taxes paid
-Income taxes received
-
-
Noncash Investing and Financing Activities:
Accrued construction expenditures
Capital leases
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Changes in Common Equity
Common Stock
Accumulated Other Comprehensive Income (Loss)
Millions
Shares
Outstanding Amount
Treasury Amount
Retained Earnings
Gains (Losses) Cash Flow Hedges
Deferred Employee Benefit Plans
Total AOCI
Total
Balance as of January 1, 2014
$
2,289
$
(9
)
$
2,444
$
(52
)
$
(8
)
$
(60
)
$
4,664
Net Income
Other Comprehensive Income (Loss)
Losses arising during the period
(14
)
(5
)
(19
)
(19
)
Losses/amortization reclassified from AOCI
Total Comprehensive Income (Loss)
(11
)
(4
)
(15
)
Issuance of Common Stock
(1
)
Dividends Declared
(298
)
(298
)
Balance as of December 31, 2014
$
2,388
(10
)
2,684
(63
)
(12
)
(75
)
4,987
Net Income
Other Comprehensive Income (Loss)
Losses arising during the period
(12
)
-
(12
)
(12
)
Losses/amortization reclassified from AOCI
-
Total Comprehensive Income
-
Issuance of Common Stock
-
(2
)
Dividends Declared
(312
)
(312
)
Balance as of December 31, 2015
$
2,402
(12
)
3,118
(53
)
(12
)
(65
)
5,443
Net Income
Other Comprehensive Income (Loss)
Losses arising during the period
(1
)
Losses/amortization reclassified from AOCI
-
Total Comprehensive Income (Loss)
(1
)
Issuance of Common Stock
-
-
-
-
Dividends Declared
(329
)
(329
)
Balance as of December 31, 2016
$
2,402
$
(12
)
$
3,384
$
(36
)
$
(13
)
$
(49
)
$
5,725
Dividends declared per share of common stock were $2.30, $2.18 and $2.10 for 2016, 2015 and 2014, respectively.
See Notes to Consolidated Financial Statements.
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, 2016 and 2015, and the related consolidated statements of comprehensive income, cash flows, and changes in equity for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and the 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, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, 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 24, 2017
South Carolina Electric & Gas Company and Affiliates
Consolidated Balance Sheets
December 31, (Millions of dollars)
Assets
Utility Plant In Service
$
11,510
$
11,153
Accumulated Depreciation and Amortization
(3,991
)
(3,869
)
Construction Work in Progress
4,813
3,997
Nuclear Fuel, Net of Accumulated Amortization
Utility Plant, Net ($756 and $700 related to VIEs)
12,603
11,589
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation
Assets held in trust, net-nuclear decommissioning
Other investments
Nonutility Property and Investments, Net
Current Assets:
Cash and cash equivalents
Receivables:
Customer, net of allowance for uncollectible accounts of $3 and $3
Affiliated companies
Income taxes
-
Other
Inventories:
Fuel
Materials and supplies
Prepayments
Other current assets
Total Current Assets ($85 and $88 related to VIEs)
1,020
1,019
Deferred Debits and Other Assets:
Regulatory assets
2,030
1,857
Other
Total Deferred Debits and Other Assets ($52 and $53 related to VIEs)
2,273
1,973
Total
$
16,091
$
14,765
See Notes to Consolidated Financial Statements.
December 31, (Millions of dollars)
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding for all periods presented
$
2,860
$
2,760
Retained Earnings
2,481
2,265
Accumulated Other Comprehensive Loss
(3
)
(3
)
Total Common Equity
5,338
5,022
Noncontrolling interest
Total Equity
5,472
5,151
Long-Term Debt, net
5,154
4,659
Total Capitalization
10,626
9,810
Current Liabilities:
Short-term borrowings
Current portion of long-term debt
Accounts payable
Affiliated payables
Customer deposits and customer prepayments
Taxes accrued
Interest accrued
Dividends declared
Derivative financial instruments
Other
Total Current Liabilities
1,736
1,740
Deferred Credits and Other Liabilities:
Deferred income taxes, net
1,939
1,732
Asset retirement obligations
Pension and postretirement benefits
Unrecognized tax benefits
Regulatory liabilities
Other
Other - affiliate
Total Deferred Credits and Other Liabilities
3,729
3,215
Commitments and Contingencies (Note 10)
-
-
Total
$
16,091
$
14,765
See Notes to Consolidated Financial Statements.
South Carolina Electric & Gas Company and Affiliates
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, (Millions of dollars)
Operating Revenues:
Electric
$
2,614
$
2,551
$
2,621
Electric - nonconsolidated affiliate
Gas
Gas - nonconsolidated affiliate
Total Operating Revenues
2,986
2,930
3,091
Operating Expenses:
Fuel used in electric generation
Fuel used in electric generation - nonconsolidated affiliate
Purchased power
Gas purchased for resale
Gas purchased for resale - nonconsolidated affiliate
Other operation and maintenance
Other operation and maintenance - nonconsolidated affiliate
Depreciation and amortization
Other taxes
Other taxes - nonconsolidated affiliate
Total Operating Expenses
1,973
1,996
2,261
Operating Income
1,013
Other Income (Expense):
Other income
Other expenses
(24
)
(31
)
(34
)
Interest charges, net of allowance for borrowed funds used during construction of $18, $14 and $14
(270
)
(248
)
(228
)
Allowance for equity funds used during construction
Total Other Expense
(239
)
(223
)
(154
)
Income Before Income Tax Expense
Income Tax Expense
Net Income and Total Comprehensive Income
Less Net Income and Total Comprehensive Income Attributable to Noncontrolling Interest
Earnings and Comprehensive Income Available to Common Shareholder
$
$
$
Dividends Declared on Common Stock
$
$
$
See Notes to Consolidated Financial Statements.
South Carolina Electric & Gas Company and Affiliates
Consolidated Statements of Cash Flows
For the Years Ended December 31, (Millions of dollars)
Cash Flows From Operating Activities:
Net income
$
$
$
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net
Depreciation and amortization
Amortization of nuclear fuel
Allowance for equity funds used during construction
(26
)
(25
)
(28
)
Carrying cost recovery
(17
)
(12
)
(9
)
Changes in certain assets and liabilities:
Receivables
(47
)
Receivables - affiliate
(3
)
(90
)
Income tax receivable
(53
)
-
-
Inventories
(35
)
(24
)
(52
)
Prepayments
(4
)
(89
)
Regulatory assets
(94
)
(29
)
(116
)
Other regulatory liabilities
(5
)
(3
)
(103
)
Accounts payable
(49
)
Accounts payable - affiliate
(17
)
Unrecognized tax benefits
Taxes accrued
(104
)
(53
)
Pension and other postretirement benefits
(5
)
Other assets
(99
)
(15
)
Other liabilities
(28
)
Other liabilities - affiliate
(1
)
(6
)
(9
)
Net Cash Provided From Operating Activities
1,078
Cash Flows From Investing Activities:
Property additions and construction expenditures
(1,399
)
(1,008
)
(934
)
Proceeds from investments and sales of assets (including derivative collateral returned)
Purchase of investments (including derivative collateral posted)
(740
)
(887
)
(381
)
Payments upon interest rate derivative contract settlement
(113
)
(263
)
(95
)
Proceeds from interest rate derivative contract settlement
-
-
Proceeds from investment in affiliate
-
Investment in affiliate
-
-
(80
)
Net Cash Used For Investing Activities
(1,449
)
(1,102
)
(1,215
)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt
Repayment of long-term debt
(112
)
(11
)
(48
)
Dividends
(301
)
(285
)
(260
)
Short-term borrowings, net
(289
)
Short-term borrowings-nonconsolidated affiliate, net
(4
)
(50
)
Contribution from parent
Return of capital to parent
-
(4
)
(7
)
Deferred financing costs
-
(2
)
-
Net Cash Provided From Financing Activities
Net Increase in Cash and Cash Equivalents
Cash and Cash Equivalents, January 1
Cash and Cash Equivalents, December 31
$
$
$
Supplemental Cash Flow Information:
Cash for-Interest paid (net of capitalized interest of $18, $14 and $14)
$
$
$
-Income taxes paid
-Income taxes received
-
Noncash Investing and Financing Activities:
Accrued construction expenditures
Capital leases
See Notes to Consolidated Financial Statements.
South Carolina Electric & Gas Company and Affiliates
Consolidated Statements of Changes in Equity
Common Stock
Millions
Shares
Amount
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Non-controlling
Interest
Total
Equity
Balance at January 1, 2014
$
2,479
$
1,896
$
(3
)
$
$
4,489
Earnings available for common shareholder
Deferred cost of employee benefit plans, net of tax $-
-
-
Total Comprehensive Income
-
Capital contributions from parent
Cash dividends declared
(265
)
(7
)
(272
)
Balance at December 31, 2014
2,560
2,077
(3
)
4,757
Earnings Available for Common Shareholder
Deferred Cost of Employee Benefit Plans, net of tax $-
-
-
Total Comprehensive Income
-
Capital contributions from parent
-
Cash dividends declared
(278
)
(8
)
(286
)
Balance at December 31, 2015
2,760
2,265
(3
)
5,151
Earnings Available for Common Shareholder
Deferred Cost of Employee Benefit Plans, net of tax $-
-
-
Total Comprehensive Income
-
Capital contributions from parent
-
Cash dividends declared
(297
)
(8
)
(305
)
Balance at December 31, 2016
$
2,860
$
2,481
$
(3
)
$
$
5,472
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
South Carolina Electric & Gas Company and Affiliates
Notes to Consolidated Financial Statements
The following notes to the consolidated financial statements are a combined presentation. Except as otherwise indicated herein, each note applies to the Company and Consolidated SCE&G; however, Consolidated SCE&G makes no representation as to information relating solely to SCANA Corporation or its subsidiaries (other than Consolidated SCE&G).
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Principles of Consolidation
The Company
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, the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia and conducts other energy-related business.
The accompanying consolidated financial statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and subsidiaries that formerly were wholly-owned during the periods presented.
Regulated businesses
Nonregulated businesses
South Carolina Electric & Gas Company
SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc.
ServiceCare, Inc.
South Carolina Generating Company, Inc.
SCANA Services, Inc.
Public Service Company of North Carolina, Incorporated
SCANA Corporate Security Services, Inc.
SCANA Communications Holdings, Inc.
SCANA 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. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.
Consolidated SCE&G
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.
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's 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. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.
GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, 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 $485 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 and other environmental allowances. See also Note 4.
Dispositions
In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million. The pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's consolidated statement of income.
CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within All Other in Note 12. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations.
Use of Estimates
The preparation of financial statements in conformity with GAAP 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.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current presentation, as follows:
Statements of Cash Flows - For the Company and Consolidated SCE&G, non-cash changes in fair value of interest rate swaps were reclassified as an offset to the changes in certain assets and liabilities section within the reconciliations of Net Income to Net Cash Provided From Operating Activities as follows:
December 31,
Millions of dollars
Derivative financial instruments
$
(174
)
$
Regulatory assets
(234
)
Regulatory liabilities
(29
)
Other assets
(15
)
Other liabilities
In addition, due to insignificance, the caption for Losses from equity method investments has been eliminated, and the amounts have been reclassified and included within the caption of Changes in Other assets.
The reclassifications above had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the consolidated statements of cash flows.
Statements of Comprehensive Income - For Consolidated SCE&G, operating revenues and operating expenses from transactions with nonconsolidated affiliates are presented separately. A detail of such transactions are included in Note 11.
Segment of Business Information Disclosure - For the Company, the Gas Marketing segment includes the information formerly reported in two separate marketing segments. See Note 12 for the required disclosures.
Utility Plant
Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, 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 5.3% for 2016, 6.1% for 2015, and 7.2% for 2014. Consolidated SCE&G calculated AFC using average composite rates of 4.7% for 2016, 5.6% for 2015, and 6.5% for 2014. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.
Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property. In 2015, SCE&G adopted lower depreciation rates for electric and common plant, as approved by the SCPSC and further described in Note 2. In addition, CGT was sold in the first quarter of 2015 (see Dispositions herein) and excluded from the 2015 calculation of composite weighted average depreciation rates. The composite weighted average depreciation rates for utility plant assets were as follows:
SCE&G
2.56
%
2.55
%
2.85
%
GENCO
2.66
%
2.66
%
2.66
%
CGT
-
-
2.11
%
PSNC Energy
2.90
%
2.94
%
2.98
%
Weighted average of above
2.61
%
2.61
%
2.84
%
Consolidated SCE&G
2.56
%
2.56
%
2.84
%
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 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 is included in the corresponding operating expenses on its income statement.
As of December 31,
Unit 1
New Units
Unit 1
New Units
Percent owned
66.7%
55.0%
66.7%
55.0%
Plant in service
$
1.3
billion
-
$
1.2
billion
-
Accumulated depreciation
$
634.4
million
-
$
620.4
million
-
Construction work in progress
$
167.7
million
$
4.2
billion
$
214.6
million
$
3.4
billion
For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10.
Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Unit 1 and the New Units. These amounts totaled $76.2 million at December 31, 2016 and $178.8 million at December 31, 2015.
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. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred.
SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2016, and 2015, SCE&G incurred $23.8 million and $16.5 million, respectively, for turbine maintenance.
Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $26.8 million for the Fall 2015 outage and $1.8 million in 2016 in preparation for the Spring 2017 outage.
Goodwill
The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. Accounting guidance adopted by the Company gives it the option to perform a qualitative assessment of impairment ("step zero"). Based on this qualitative 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 is not required to proceed with a two-step quantitative assessment. If the quantitative assessment becomes necessary, step one requires estimation of the fair value of the reporting unit and the comparison of that amount to its carrying value. 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. Should a write-down be required, such a charge would be treated as an operating expense.
For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company utilized the step zero qualitative assessment in its evaluation as of January 1, 2017 and was not required to use the two-step quantitative assessment. In evaluations for preceding periods, the Company's step one assessment utilized the assistance of an independent appraisal in determining its estimate of fair value. In such evaluations, step one indicated no impairment, and no impairment charges were recorded.
Nuclear Decommissioning
Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $786.4 million, stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will 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, SCE&G transfers to an external trust fund the amounts collected through rates ($3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. 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 Unit 1 on an after-tax basis.
Cash and Cash Equivalents
Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills.
Receivables
Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described below. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.
Other receivables consist primarily of amounts due from Santee Cooper related to the construction and operation of jointly owned nuclear generating facilities at Summer Station.
Inventories
Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
PSNC Energy utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. The counterparty held, through an agency relationship, 40% and 46% of PSNC Energy’s natural gas inventory at December 31, 2016 and December 31, 2015, respectively, with a carrying value of $9.8 million and $17.7 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. PSNC Energy expects to replace this agreement when it expires on March 31, 2017.
Income Taxes
SCANA files consolidated federal income tax returns. 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.
Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. 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
The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods different from the periods in which the costs would be charged to expense, or record revenues in periods different from the periods in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Deferred amounts expected to be recovered or repaid within 12 months are classified in the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.
Debt Issuance Premiums, Discounts and Other Costs
Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, 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
An environmental assessment program is maintained 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 regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.
Income Statement Presentation
Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 12) are presented within Operating Income, and all other
activities are presented within Other Income (Expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within Operating Income and the 2015 gain on the sale of SCI within Other Income (Expense).
Revenue Recognition
Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $178.9 million at December 31, 2016 and $129.1 million at December 31, 2015 for the Company. Unbilled revenues totaled $117.6 million at December 31, 2016 and $101.5 million at December 31, 2015 for Consolidated SCE&G.
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent hearings.
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 and amounts contained in rates is adjusted through revenue and 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.
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 billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income.
Earnings Per Share
Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, diluted earnings per share are computed using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.
New Accounting Matters
In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation.
In May 2015, the FASB issued accounting guidance removing the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the NAV practical expedient. Disclosures about investments in
certain entities that calculate NAV per share are limited under this guidance to those investments for which the entity has elected to estimate the fair value using the NAV practical expedient. The Company and Consolidated SCE&G elected to adopt this guidance on a retrospective basis. The adoption resulted in the reclassification of fair value related to the pension plan’s investment in the common collective trust, joint venture interest, and limited partnership as of December 31, 2015. See Note 8.
In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter of 2017 and do not expect it to have a significant impact on their respective financial statements.
In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined adoption of this guidance will not have a significant impact on their respective financial statements.
In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further, and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun. In addition, the Company and Consolidated SCE&G have begun evaluating certain third party software tools that may assist with this implementation and ongoing compliance.
In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities are required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G adopted this guidance in the fourth quarter of 2016 and, based on the nature of their share-based awards practices, the adoption had no impact on their respective financial statements.
In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in certain impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.
In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.
In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter 2017 and it is not expected to have a material impact on their respective financial statements.
In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018 and the Company and Consolidated SCE&G expect no impact on their respective financial statements.
In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The same one-step impairment test will be applied to goodwill at all reporting units, even those with zero or negative carrying amounts. The guidance is effective for years beginning in 2020,
though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that adoption will have a material impact on their respective financial statements.
2. RATE AND OTHER REGULATORY MATTERS
Rate Matters
Electric - Cost of Fuel
SCE&G's retail electric rates include 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.
Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments were fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs from May 1, 2014 through April 30, 2015.
The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.
By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015.
By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G, ORS, and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity.
By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $29 million ($.12 per share) in 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million ($.06 per share) with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, SCE&G's net income for 2015 increased approximately $9.8 million as a result of this change in estimate.
By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016.
In October 2016, the SCPSC initiated its 2017 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 6, 2017.
Electric - Base Rates
Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are
recorded as a regulatory asset and other income. Carrying costs totaled $14.0 million and $9.5 million during 2016 and 2015, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.
The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:
Year
Effective
Amount
First billing cycle of May
$37.6 million
First billing cycle of May
$32.0 million
First billing cycle of May
$15.4 million
In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts.
By order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs rider. The increased pension rider is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.
In January 2017, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of $37.0 million of costs and net lost revenues associated with the DSM Programs, along with an incentive to invest in such programs.
Electric - BLRA
Under the BLRA, SCE&G may 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. Rate adjustments are based on SCE&G's updated cost of debt and capital structure and on an allowed ROE. The SCPSC has approved recovery of the following amounts.
Year
Increase
Effective for bills rendered on and after
Amount
Allowed ROE
2.7%
November 27
$64.4 million
10.50%
*
2.6%
October 30
$64.5 million
11.00%
2.8%
October 30
$66.2 million
11.00%
*Applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016.
In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option.
The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million. SCE&G’s total project capital cost is now estimated at approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25%. This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is
denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. See also New Nuclear Construction in Note 10.
On December 14, 2016, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement. These parties may appeal this decision to the South Carolina Supreme Court once the SCPSC’s order has been issued. SCE&G cannot determine when the SCPSC will issue its order in this matter or if that order will be appealed.
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 first billing cycle of November in the following years:
Year
Action
Amount
1.2
%
Increase
$4.1 million
No change
-
0.6
%
Decrease
$2.6 million
SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. 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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2016, 2015 and 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each of the review periods were reasonable and prudent.
Gas - PSNC Energy
PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.
PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection 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.
On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. In addition, PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs resulting from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. The new rates are effective for services rendered on or after November 1, 2016.
In November 2016, in connection with PSNC Energy's 2016 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, 2016.
Regulatory Assets and Regulatory Liabilities
Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
The Company
Consolidated SCE&G
December 31,
December 31,
Millions of dollars
Regulatory Assets:
Accumulated deferred income taxes
$
$
$
$
AROs and related funding
Deferred employee benefit plan costs
Deferred losses on interest rate derivatives
Unrecovered plant
Environmental remediation costs
DSM Programs
Pipeline integrity management costs
Carrying costs on deferred tax assets related to nuclear construction
Deferred storm damage costs
-
-
Deferred costs related to uncertain tax position
-
-
Other
Total Regulatory Assets
$
2,130
$
1,937
$
2,030
$
1,857
Regulatory Liabilities:
Asset removal costs
$
$
$
$
Deferred gains on interest rate derivatives
Other
Total Regulatory Liabilities
$
$
$
$
Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset. A substantial portion of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. 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. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 11 years.
Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.
Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.
Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years.
DSM Programs represent SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider.
Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines located near moderate to high density populations. PSNC Energy will recover costs totaling $20.3 million over a five-year period beginning November 2016, and remaining costs of $7.0 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015.
Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020.
Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates.
Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5.
Various other regulatory assets are expected to be recovered through rates over periods up to 2047.
Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.
The SCPSC, the NCUC or the FERC has 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 specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. 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 or Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.
3. COMMON EQUITY
SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock. However, SCE&G’s bond indenture and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company and, in the case of SCE&G, Consolidated SCE&G consider to be remote, could limit the payment of cash dividends on their respective common stock.
The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2016 and 2015, retained earnings of approximately $79.0 million and $72.4 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.
Authorized shares of common stock were 200 million as of December 31, 2016 and 2015.
SCANA issued no common stock during the year ended December 31, 2016. SCANA issued common stock valued at $14.3 million (when issued) during the year ended December 31, 2015, to satisfy the requirements of deferred compensation and dividend reinvestment plans.
Authorized shares of SCE&G common stock were 50 million as of December 31, 2016 and 2015. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA as of December 31, 2016 and 2015.
4. LONG-TERM AND SHORT-TERM DEBT
Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows:
The Company
December 31,
Dollars in millions
Maturity
Balance
Rate
Balance
Rate
SCANA Medium Term Notes (unsecured)
-
$
5.42
%
$
5.42
%
SCANA Senior Notes (unsecured) (a)
-
1.63
%
1.11
%
SCE&G First Mortgage Bonds (secured)
-
4,840
5.79
%
4,340
5.78
%
GENCO Notes (secured)
-
5.93
%
5.92
%
Industrial and Pollution Control Bonds (b)
-
3.51
%
3.51
%
PSNC Energy Senior Debentures and Notes
-
5.53
%
5.93
%
Nuclear Fuel Financing
-
-
%
0.78
%
Other
-
2.76
%
2.72
%
Total debt
6,531
6,034
Current maturities of long-term debt
(17
)
(116
)
Unamortized discount, net
(1
)
-
Unamortized debt issuance costs
(40
)
(36
)
Total long-term debt, net
$
6,473
$
5,882
Consolidated SCE&G
December 31,
Dollars in millions
Maturity
Balance
Rate
Balance
Rate
First Mortgage Bonds (secured)
-
$
4,840
5.79
%
$
4,340
5.78
%
GENCO Notes (secured)
-
5.93
%
5.92
%
Industrial and Pollution Control Bonds (b)
-
3.51
%
3.51
%
Nuclear Fuel Financing
-
-
%
0.78
%
Other
-
2.76
%
2.63
%
Total debt
5,201
4,799
Current maturities of long-term debt
(12
)
(110
)
Unamortized premium, net
Unamortized debt issuance costs
(36
)
(32
)
Total long-term debt, net
$
5,154
$
4,659
(a) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17%).
(b) Includes variable rate debt of $67.8 million at December 31, 2016 (rate of 0.76%) and 2015 (rate of 0.03%) which are hedged by fixed swaps.
In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.
In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.
In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.
The Company's long-term debt maturities will be $17 million in 2017, $726 million in 2018, $15 million in 2019, $365 million in 2020 and $493 million in 2021. These amounts include, for Consolidated SCE&G, $12 million in 2017, $722 million in 2018, $11 million in 2019, $10 million in 2020 and $39 million in 2021.
Substantially all electric utility plant is pledged as collateral in connection with long-term debt.
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, 2016, the Bond Ratio was 5.12.
Lines of Credit and Short-Term Borrowings
At December 31, 2016 and 2015, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings:
December 31, 2016
Millions of dollars
Total
SCANA
SCE&G
PSNC Energy
Lines of credit:
Five-year, expiring December 2020
$
1,300.0
$
400.0
$
700.0
$
200.0
Fuel Company five-year, expiring December 2020
$
500.0
-
$
500.0
-
Three-year, expiring December 2018
$
200.0
-
$
200.0
-
Total committed long-term
$
2,000.0
$
400.0
$
1,400.0
$
200.0
Outstanding commercial paper (270 or fewer days)
$
940.5
$
64.4
$
804.3
$
71.8
Weighted average interest rate
1.43
%
1.04
%
1.07
%
Letters of credit supported by LOC
$
3.3
$
3.0
$
0.3
-
Available
$
1,056.2
$
332.6
$
595.4
$
128.2
December 31, 2015
Lines of credit:
Five-year, expiring December 2020
$
1,300.0
$
400.0
$
700.0
$
200.0
Fuel Company five-year, expiring December 2020
$
500.0
-
$
500.0
-
Three-year, expiring December 2018
$
200.0
-
$
200.0
-
Total committed long-term
$
2,000.0
$
400.0
$
1,400.0
$
200.0
Outstanding commercial paper (270 or fewer days)
$
531.4
$
37.4
$
420.2
$
73.8
Weighted average interest rate
1.19
%
0.74
%
0.77
%
Letters of credit supported by LOC
$
3.3
$
3.0
$
0.3
-
Available
$
1,465.4
$
359.6
$
979.6
$
126.2
SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to credit agreements in the amounts and for the terms described above. 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 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9%, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.
Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019.
Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At December 31, 2016 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $29 million. At December 31, 2015 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33 million and money pool investments due from an affiliate of $9 million. On SCE&G's consolidated balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.
5. INCOME TAXES
Components of income tax expense are as follows:
The Company
Consolidated SCE&G
Millions of dollars
Current taxes:
Federal
$
$
$
$
$
$
State
(4
)
(6
)
Total current taxes
Deferred tax (benefit) expense, net:
Federal
(36
)
(3
)
State
(7
)
(3
)
Total deferred taxes
(43
)
(6
)
Investment tax credits:
Amortization of amounts deferred-state
-
(1
)
(1
)
-
(1
)
(1
)
Amortization of amounts deferred-federal
(2
)
(2
)
(3
)
(2
)
(2
)
(3
)
Total investment tax credits
(2
)
(3
)
(4
)
(2
)
(3
)
(4
)
Total income tax expense
$
$
$
$
$
$
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 Company
Consolidated SCE&G
Millions of dollars
Net income
$
$
$
$
$
$
Income tax expense
Noncontrolling interest
-
-
-
Total pre-tax income
$
$
1,139
$
$
$
$
Income taxes on above at statutory federal income tax rate
$
$
$
$
$
$
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)
State investment tax credits (less federal income tax effect)
(5
)
(6
)
(5
)
(5
)
(6
)
(5
)
Allowance for equity funds used during construction
(10
)
(9
)
(11
)
(9
)
(9
)
(10
)
Deductible dividends-401(k) Retirement Savings Plan
(10
)
(10
)
(10
)
-
-
-
Amortization of federal investment tax credits
(2
)
(2
)
(3
)
(2
)
(2
)
(3
)
Section 41 tax credits
-
(3
)
-
(3
)
Section 45 tax credits
(8
)
(9
)
(9
)
(8
)
(9
)
(9
)
Domestic production activities deduction
(23
)
(18
)
(7
)
(23
)
(18
)
(7
)
Realization of basis differences upon sale of subsidiaries
-
-
-
-
-
Other differences, net
(1
)
(3
)
(2
)
(3
)
Total income tax expense
$
$
$
$
$
$
The tax effects of significant temporary differences comprising net deferred tax liability are as follows:
The Company
Consolidated SCE&G
Millions of dollars
Deferred tax assets:
Nondeductible accruals
$
$
$
$
Asset retirement obligation, including nuclear decommissioning
Financial instruments
-
Unamortized investment tax credits
Deferred fuel costs
Other
Total deferred tax assets
Deferred tax liabilities:
Property, plant and equipment
2,159
1,906
1,856
1,644
Deferred employee benefit plan costs
Regulatory asset, asset retirement obligation
Regulatory asset, unrecovered plant
Demand side management costs
Prepayments
Other
Total deferred tax liabilities
2,584
2,305
2,232
1,998
Net deferred tax liability
$
2,159
$
1,907
$
1,939
$
1,732
The State of North Carolina lowered its corporate income tax rate from 6.9% to 6.0% in 2014, 5.0% in 2015, 4% in 2016 and 3% effective January 1, 2017. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
The Company files consolidated federal income tax returns which includes Consolidated SCE&G, 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. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below in Changes in Unrecognized Tax Benefits. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.
Changes in Unrecognized Tax Benefits
The Company
Consolidated SCE&G
Millions of dollars
Unrecognized tax benefits, January 1
$
$
$
$
$
$
Gross increases-uncertain tax positions in prior period
-
-
Gross decreases-uncertain tax positions in prior period
-
(2
)
-
-
(2
)
-
Gross increases-current period uncertain tax positions
Unrecognized tax benefits, December 31
$
$
$
$
$
$
During 2013 and 2014, SCANA amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models.
The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of
the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns.
These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of December 31, 2016, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $350 million ($219 million and $236 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $292 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $49 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2016.
In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).
Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. In 2016, the amount recorded for such interest income is $1.8 million and interest expense is $0.9 million. Such amounts were not significant in 2015 or 2014. No amounts have been recorded for tax penalties for any periods presented.
6. DERIVATIVE FINANCIAL INSTRUMENTS
Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation.
Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. 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 Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant 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 companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows.
PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. 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 under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.
Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI 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, SCANA Energy, 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. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.
Interest Rate Swaps
Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.
Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt. Except as described in the following paragraph, 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. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.
Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.
Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.
Quantitative Disclosures Related to Derivatives
The Company was party to natural gas derivative contracts outstanding in the following quantities:
Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation
Gas Distribution
Gas Marketing
Total
As of December 31, 2016
Commodity
4,510,000
11,947,000
16,457,000
Energy Management (a)
-
67,447,223
67,447,223
Total (a)
4,510,000
79,394,223
83,904,223
As of December 31, 2015
Commodity
7,530,000
11,842,500
19,372,500
Energy Management (a)
-
38,857,480
38,857,480
Total (a)
7,530,000
50,699,980
58,229,980
(a) Includes amounts related to basis swap contracts totaling 730,721 MMBTU in 2016 and 1,842,048 MMBTU in 2015.
The aggregate notional amounts of the interest rate swaps were as follows:
The Company
Consolidated SCE&G
Millions of dollars
December 31, 2016
December 31, 2015
December 31, 2016
December 31, 2015
Designated as hedging instruments
$
115.6
$
120.0
$
36.4
$
36.4
Not designated as hedging instruments
1,285.0
1,235.0
1,285.0
1,235.0
The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.
Fair Values of Derivative Instruments
The Company
Consolidated SCE&G
Millions of dollars
Balance Sheet Location
Asset
Liability
Asset
Liability
As of December 31, 2016
Designated as hedging instruments
Interest rate contracts
Derivative financial instruments
$
$
Other deferred credits and other liabilities
Commodity contracts
Prepayments
$
Other current assets
Total
$
$
-
$
Not designated as hedging instruments
Interest rate contracts
Other deferred debits and other assets
$
$
Derivative financial instruments
$
$
Other deferred credits and other liabilities
Commodity contracts
Other current assets
Energy management contracts
Prepayments
Other current assets
Other deferred debits and other assets
Derivative financial instruments
Other deferred credits and other liabilities
Total
$
$
$
$
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
Derivative financial instruments
$
$
Other deferred credits and other liabilities
Commodity contracts
Other current assets
Derivative financial instruments
Total
-
$
-
$
Not designated as hedging instruments
Interest rate contracts
Other current assets
$
$
Other deferred debits and other assets
Derivative financial instruments
$
$
Other deferred credits and other liabilities
Commodity contracts
Other current assets
Energy management contracts
Other current assets
Other deferred debits and other assets
Derivative financial instruments
Other deferred credits and other liabilities
Total
$
$
$
$
Derivatives Designated as Fair Value Hedges
The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.
Derivatives in Cash Flow Hedging Relationships
The effect of derivative instruments on the consolidated statements of income is as follows:
The Company and Consolidated SCE&G:
Loss Deferred in Regulatory Accounts
Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars
(Effective Portion)
Location
Amount
Year Ended December 31, 2016
Interest rate contracts
-
Interest expense
$
(2
)
Year Ended December 31, 2015
Interest rate contracts
$
(3
)
Interest expense
$
(3
)
Year Ended December 31, 2014
Interest rate contracts
$
(9
)
Interest expense
$
(3
)
The Company:
Gain or (Loss)
Recognized in OCI, net of tax
Gain (Loss) Reclassified from AOCI into Income,
net of tax (Effective Portion)
Millions of dollars
(Effective Portion)
Location
Amount
Year Ended December 31, 2016
Interest rate contracts
$
(1
)
Interest expense
$
(7
)
Commodity contracts
Gas purchased for resale
(6
)
Total
$
$
(13
)
Year Ended December 31, 2015
Interest rate contracts
$
(2
)
Interest expense
$
(7
)
Commodity contracts
(10
)
Gas purchased for resale
(15
)
Total
$
(12
)
$
(22
)
Year Ended December 31, 2014
Interest rate contracts
$
(6
)
Interest expense
$
(7
)
Commodity contracts
(8
)
Gas purchased for resale
Total
$
(14
)
$
(3
)
As of December 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $5.4 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019.
As of December 31, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.8 million as an increase to interest expense assuming financial markets remain at their current levels.
Hedge Ineffectiveness
For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented.
Derivatives Not Designated as Hedging Instruments
The Company and Consolidated SCE&G:
Loss Deferred in Regulatory Accounts
Gain (Loss) Reclassified from
Deferred Accounts into Income
Millions of dollars
Location
Amount
Year Ended December 31, 2016
Interest rate contracts
$
(34
)
Interest Expense
$
(2
)
Year Ended December 31, 2015
Interest rate contracts
$
(69
)
Other income
$
Year Ended December 31, 2014
Interest rate contracts
$
(352
)
Other income
$
Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2.
As of December 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $2.4 million as an increase to interest expense.
Credit Risk Considerations
Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.
Derivative Contracts with Credit Contingent Features
The Company
Consolidated SCE&G
Millions of dollars
December 31, 2016
December 31, 2015
December 31, 2016
December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position
$
50.3
$
95.2
$
30.3
$
57.0
Fair value of collateral already posted
29.2
50.4
9.2
13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered
21.1
44.8
21.1
43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position
$
62.9
$
7.3
$
62.0
$
7.3
Fair value of collateral already posted
-
-
-
-
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered
62.9
7.3
62.0
7.3
In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $1.5 million related to $9.0 million in commodity derivatives that are in a net asset position at December 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered.
Information related to the offsetting derivative assets follows:
Derivative Assets
The Company
Consolidated SCE&G
Millions of dollars
Interest Rate Contracts
Commodity Contracts
Energy Management Contracts
Total
Interest Rate Contracts
As of December 31, 2016
Gross Amounts of Recognized Assets
$
$
$
$
$
Gross Amounts Offset in Statement of Financial Position
(4
)
(4
)
Net Amounts Presented in Statement of Financial Position
Gross Amounts Not Offset - Financial Instruments
(9
)
(9
)
(9
)
Gross Amounts Not Offset - Cash Collateral Received
Net Amount
$
$
$
$
$
Balance sheet location
Prepayments
$
Other current assets
Other deferred debits and other assets
$
Total
$
$
As of December 31, 2015
Gross Amounts of Recognized Assets
$
$
$
$
$
Gross Amounts Offset in Statement of Financial Position
(1
)
(1
)
Net Amounts Presented in Statement of Financial Position
Gross Amounts Not Offset - Financial Instruments
(8
)
(8
)
(8
)
Gross Amounts Not Offset - Cash Collateral Received
Net Amount
$
$
$
$
$
Balance sheet location
Other current assets
$
$
Other deferred debits and other assets
Total
$
$
Information related to the offsetting of derivative liabilities follows:
Derivative Liabilities
The Company
Consolidated SCE&G
Millions of dollars
Interest Rate Contracts
Commodity Contracts
Energy Management Contracts
Total
Interest Rate Contracts
As of December 31, 2016
Gross Amounts of Recognized Liabilities
$
$
$
$
Gross Amounts Offset in Statement of Financial Position
(3
)
(3
)
Net Amounts Presented in Statement of Financial Position
-
Gross Amounts Not Offset - Financial Instruments
(9
)
(9
)
(9
)
Gross Amounts Not Offset - Cash Collateral Posted
(29
)
(29
)
(9
)
Net Amount
$
-
$
$
$
Balance sheet location
Derivative financial instruments
$
$
Other deferred credits and other liabilities
Total
$
$
As of December 31, 2015
Gross Amounts of Recognized Liabilities
$
$
$
$
$
Gross Amounts Offset in Statement of Financial Position
(1
)
(1
)
Net Amounts Presented in Statement of Financial Position
Gross Amounts Not Offset - Financial Instruments
(8
)
(8
)
(8
)
Gross Amounts Not Offset - Cash Collateral Posted
(36
)
(5
)
(9
)
(50
)
(13
)
Net Amount
$
$
-
$
$
$
Balance sheet location
Other current assets
$
Derivative financial instruments
$
Other deferred credits and other liabilities
Total
$
$
7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
Available for sale securities are valued using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative and energy management 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. 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:
As of December 31, 2016
As of December 31, 2015
The Company
Consolidated SCE&G
The Company
Consolidated SCE&G
Millions of dollars
Level 1
Level 2
Level 2
Level 1
Level 2
Level 2
Assets:
Available for sale securities
$
-
-
$
-
-
Held to maturity securities
-
$
-
-
-
-
Interest rate contracts
-
$
-
$
$
Commodity contracts
-
-
-
Energy management contracts
-
-
-
Liabilities:
Interest rate contracts
-
-
Commodity contracts
-
-
-
-
Energy management contracts
-
-
There were no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented.
Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2016 and December 31, 2015 were as follows:
As of December 31, 2016
As of December 31, 2015
Millions of dollars
Carrying
Amount
Estimated
Fair Value
Carrying
Amount
Estimated
Fair Value
The Company
$
6,489.8
$
7,183.3
$
5,997.6
$
6,445.7
Consolidated SCE&G
5,166.0
5,752.3
4,769.0
5,129.1
Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.
Carrying values of short-term borrowings approximate their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2.
8. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension and Other Postretirement Benefit Plans
SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. SCE&G participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary.
The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. 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. Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits.
In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&G participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.
The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans.
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 pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.
The Company
Consolidated SCE&G
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Benefit obligation, January 1
$
855.4
$
919.5
$
253.6
$
268.2
$
724.0
$
773.7
$
191.7
$
204.1
Service cost
20.7
24.1
4.4
5.3
16.9
19.3
3.6
4.4
Interest cost
39.4
38.2
12.1
11.4
33.4
32.2
9.9
9.4
Plan participants’ contributions
-
-
1.7
2.4
-
-
1.3
1.9
Actuarial (gain) loss
45.0
(62.4
)
14.0
(21.2
)
41.8
(47.0
)
11.5
(15.7
)
Benefits paid
(56.2
)
(64.0
)
(11.1
)
(12.5
)
(47.7
)
(54.2
)
(9.1
)
(10.3
)
Amounts Funded to parent
n/a
n/a
n/a
n/a
-
-
(1.7
)
(2.1
)
Benefit obligation, December 31
$
904.3
$
855.4
$
274.7
$
253.6
$
768.4
$
724.0
$
207.2
$
191.7
In 2015, based on an evaluation of the mortality experience of the pension plan, a custom mortality table was adopted for purposes of measuring pension and other postretirement benefit obligations at year-end. This change resulted in an actuarial gain for pension and other postretirement benefit obligations for the Company of approximately $21.5 million and $2.4 million, respectively. This change resulted in an actuarial gain for pension and other postretirement benefit obligations for Consolidated SCE&G of approximately $18.2 million and $2.0 million, respectively.
The accumulated benefit obligation for pension benefits for the Company was $874.3 million at the end of 2016 and $829.3 million at the end of 2015. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $742.9 million at the end of 2016 and $702.0 million at the end of 2015.The accumulated pension benefit obligation differs from the projected pension 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:
Pension Benefits
Other Postretirement Benefits
Annual discount rate used to determine benefit obligation
4.22
%
4.68
%
4.30
%
4.78
%
Assumed annual rate of future salary increases for projected benefit obligation
3.00
%
3.00
%
3.00
%
3.00
%
A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease gradually to 5.0% for 2021 and to remain at that level thereafter.
A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $0.8 million at December 31, 2016 and by $0.8 million at December 31, 2015. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.7 million at December 31, 2016 and by $0.7 million at December 31, 2015. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2016 and by $0.6 million at December 31, 2015. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.6 million at December 31, 2016 and by $0.6 million at December 31, 2015.
Funded Status
The Company
Consolidated SCE&G
Millions of Dollars
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
December 31,
Fair value of plan assets
$
793.6
$
781.7
-
-
$
732.9
$
720.1
-
-
Benefit obligation
904.3
855.4
$
274.7
$
253.6
768.4
724.0
$
207.2
$
191.7
Funded status
$
(110.7
)
$
(73.7
)
$
(274.7
)
$
(253.6
)
$
(35.5
)
$
(3.9
)
$
(207.2
)
$
(191.7
)
Amounts recognized on the consolidated balance sheets were as follows:
The Company
Consolidated SCE&G
Millions of Dollars
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
December 31,
Current liability
-
-
$
(12.6
)
$
(11.9
)
-
-
$
(10.4
)
$
(9.8
)
Noncurrent liability
$
(110.7
)
$
(73.7
)
(262.1
)
(241.7
)
$
(35.5
)
$
(3.9
)
(196.8
)
(181.9
)
Amounts recognized in accumulated other comprehensive loss were as follows:
The Company
Consolidated SCE&G
Millions of Dollars
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
December 31,
Net actuarial loss
$
10.4
$
10.4
$
2.5
$
1.7
$
1.9
$
2.0
$
1.0
$
0.7
Prior service cost
0.1
0.2
-
-
-
-
-
-
Total
$
10.5
$
10.6
$
2.5
$
1.7
$
1.9
$
2.0
$
1.0
$
0.7
Amounts recognized in regulatory assets were as follows:
The Company
Consolidated SCE&G
Millions of Dollars
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
December 31,
Net actuarial loss
$
236.1
$
219.4
$
34.7
$
24.0
$
208.8
$
193.7
$
29.3
$
20.4
Prior service cost
2.5
5.9
-
0.3
2.2
5.2
-
0.2
Total
$
238.6
$
225.3
$
34.7
$
24.3
$
211.0
$
198.9
$
29.3
$
20.6
In connection with the joint ownership of Summer Station, pension costs attributable to Santee Cooper as of December 31, 2016 and 2015 totaled $23.4 million and $20.3 million, respectively, and was recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2016 and 2015 totaled $15.8 million and $13.8 million, respectively, and also was recorded within deferred debits.
Changes in Fair Value of Plan Assets
The Company
Consolidated SCE&G
Pension Benefits
Pension Benefits
Millions of dollars
Fair value of plan assets, January 1
$
781.7
$
861.8
$
720.1
$
783.6
Actual return (loss) on plan assets
68.1
(16.1
)
60.5
(9.3
)
Benefits paid
(56.2
)
(64.0
)
(47.7
)
(54.2
)
Fair value of plan assets, December 31
$
793.6
$
781.7
$
732.9
$
720.1
Investment Policies and Strategies
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. SCANA uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs.
The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries.
Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited.
The pension plan asset allocation at December 31, 2016 and 2015 and the target allocation for 2017 are as follows:
Percentage of Plan Assets
Target
Allocation
December 31,
Asset Category
Equity Securities
%
%
%
Fixed Income
%
%
%
Hedge Funds
%
%
%
For 2017, the expected long-term rate of return on assets will be 7.25%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously.
Fair Value Measurements
Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2016 and 2015, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
The Company
Consolidated SCE&G
Millions of dollars
Investments with fair value measure at Level 2:
Mutual funds
$
$
$
$
Short-term investment vehicles
US Treasury securities
Corporate debt securities
Municipals
Total assets in the fair value hierarchy
Investments at net asset value:
Common collective trust
Joint venture interests
Limited partnership
-
-
Total investments at fair value
$
$
$
$
For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2016 or 2015. In addition, in 2015 the fair value of pension plan assets totaling $413 million for the Company and $381 million for Consolidated SCE&G were previously depicted as mutual funds but have been reclassified as Common collective trust for the current presentation.
Mutual funds held by the plan are open-ended mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests assets are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value.
Expected Cash Flows
Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows:
Expected Benefit Payments
The Company
Consolidated SCE&G
Millions of dollars
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
$
63.1
$
12.9
$
63.1
$
10.6
65.1
13.7
65.1
11.2
64.5
14.5
64.5
11.9
64.7
15.3
64.7
12.5
67.1
15.9
67.1
13.1
2022-2026
324.4
86.0
324.4
70.5
Pension Plan Contributions
The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension plan are expected to be made for the foreseeable future based on current market conditions and assumptions.
Net Periodic Benefit Cost
Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.
Components of Net Periodic Benefit Cost
The Company
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Service cost
$
20.7
$
24.1
$
20.0
$
4.4
$
5.3
$
4.6
Interest cost
39.4
38.2
40.4
12.1
11.4
12.0
Expected return on assets
(55.9
)
(62.0
)
(66.7
)
n/a
n/a
n/a
Prior service cost amortization
3.9
4.1
4.1
0.3
0.4
0.3
Amortization of actuarial losses
14.8
13.6
4.8
0.5
2.1
-
Net periodic benefit cost
$
22.9
$
18.0
$
2.6
$
17.3
$
19.2
$
16.9
Consolidated SCE&G
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Service cost
$
16.9
$
19.3
$
16.0
$
3.6
$
4.4
$
3.6
Interest cost
33.4
32.2
34.1
9.9
9.4
9.4
Expected return on assets
(47.4
)
(52.2
)
(56.3
)
n/a
n/a
n/a
Prior service cost amortization
3.4
3.4
3.5
0.3
0.3
0.3
Amortization of actuarial losses
12.5
11.4
4.0
0.4
1.7
-
Net periodic benefit cost
$
18.8
$
14.1
$
1.3
$
14.2
$
15.8
$
13.3
In connection with regulatory orders, SCE&G recovers current pension expense through a rate rider that may be adjusted annually (for retail electric operations) or through cost of service rates (for gas operations). For retail electric operations, current pension expense is recognized based on amounts collected through its rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, SCE&G amortizes certain previously deferred pension costs. See Note 2.
Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows:
The Company
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Current year actuarial (gain) loss
$
0.6
$
2.7
$
3.1
$
0.8
$
(1.2
)
$
1.3
Amortization of actuarial losses
(0.6
)
(0.4
)
(0.2
)
-
(0.1
)
-
Amortization of prior service cost
(0.1
)
(0.1
)
(0.2
)
-
(0.1
)
-
Total recognized in OCI
$
(0.1
)
$
2.2
$
2.7
$
0.8
$
(1.4
)
$
1.3
Consolidated SCE&G
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Current year actuarial (gain) loss
-
$
0.2
$
0.2
$
0.3
$
(0.3
)
$
0.4
Amortization of actuarial losses
$
(0.1
)
(0.1
)
(0.1
)
-
-
-
Amortization of prior service cost
-
(0.1
)
(0.1
)
-
-
-
Total recognized in OCI
$
(0.1
)
$
-
$
-
$
0.3
$
(0.3
)
$
0.4
Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:
The Company
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Current year actuarial (gain) loss
$
29.4
$
9.2
$
101.3
$
11.1
$
(18.0
)
$
19.4
Amortization of actuarial losses
(12.7
)
(11.9
)
(4.0
)
(0.4
)
(1.8
)
-
Amortization of prior service cost
(3.4
)
(3.7
)
(3.2
)
(0.3
)
(0.3
)
(0.3
)
Total recognized in regulatory assets
$
13.3
$
(6.4
)
$
94.1
$
10.4
$
(20.1
)
$
19.1
Consolidated SCE&G
Pension Benefits
Other Postretirement Benefits
Millions of dollars
Current year actuarial (gain) loss
$
26.3
$
12.2
$
87.7
$
9.2
$
(14.0
)
$
15.8
Amortization of actuarial losses
(11.2
)
(10.4
)
(3.5
)
(0.3
)
(1.5
)
-
Amortization of prior service cost
(3.0
)
(3.1
)
(2.8
)
(0.2
)
(0.3
)
(0.2
)
Total recognized in regulatory assets
$
12.1
$
(1.3
)
$
81.4
$
8.7
$
(15.8
)
$
15.6
Significant Assumptions Used in Determining Net Periodic Benefit Cost
Pension Benefits
Other Postretirement Benefits
Discount rate
4.68
%
4.20
%
5.03
%
4.78
%
4.30
%
5.19
%
Expected return on plan assets
7.50
%
7.50
%
8.00
%
n/a
n/a
n/a
Rate of compensation increase
3.00
%
3.00
%
3.00
%
3.00
%
3.00
%
3.75
%
Health care cost trend rate
n/a
n/a
n/a
7.00
%
7.00
%
7.40
%
Ultimate health care cost trend rate
n/a
n/a
n/a
5.00
%
5.00
%
5.00
%
Year achieved
n/a
n/a
n/a
The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2017 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant:
Millions of Dollars
Pension Benefits
Other Postretirement Benefits
Actuarial loss
$
0.6
$
0.1
Prior service cost
0.1
-
Total
$
0.7
$
0.1
The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2017 are as follows:
The Company
Consolidated SCE&G
Millions of Dollars
Pension Benefits
Other Postretirement Benefits
Pension Benefits
Other Postretirement Benefits
Actuarial loss
$
13.6
$
1.2
$
12.0
$
1.0
Prior service cost
1.4
-
1.3
-
Total
$
15.0
$
1.2
$
13.3
$
1.0
Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's 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 not significant.
401(k) Retirement Savings Plan
SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $27.5 million in 2016, $26.2 million in 2015 and $25.8 million in 2014. These matching contributions included those made by Consolidated SCE&G, which totaled $22.9 million in 2016, $21.8 million in 2015 and $20.7 million in 2014. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and nonforfeitable at all times.
9. SHARE-BASED COMPENSATION
The LTECP 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 LTECP 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 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. Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest.
The 2014-2016 performance cycle provides for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle. The 2015-2017 and 2016-2018 awards are based on performance over a single three-year cycle. In the performance cycle for the 2014-2016 awards, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash, and 80% of the awards were granted in performance shares, each of which has a value that is equal to, and changes with, the value of a share of SCANA common stock. For each of the 2015-2017 and 2016-2018 awards, 30% are in the form of restricted share units and 70% are in the form of performance shares. Dividend equivalents are accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards are 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 (weighted 50%).
Compensation cost of 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. At the Company's discretion, awards under the 2014-2016 performance cycle were paid in cash in February 2017 totaling $28.0 million for the Company, of which $20.2 million was attributable to Consolidated SCE&G (including amounts allocated from SCANA Services). Cash-settled liabilities related to earlier performance cycles totaled approximately $18.4 million in 2016, $20.8 million in 2015 and $11.8 million in 2014 for the Company and approximately $13.2 million in 2016, $6.3 million in 2015 and $1.9 million in 2014 for Consolidated SCE&G.
Fair value adjustments for all performance cycles resulted in compensation expense recognized in the statements of income totaling approximately $25.6 million in 2016, $18.0 million in 2015 and $20.3 million in 2014 for the Company, of which approximately $17.3 million in 2016, $12.2 million in 2015 and $12.6 million in 2014 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in capitalized compensation costs of $3.3 million in 2016, $2.3 million in 2015 and $3.1 million in 2014 for the Company and $3.1 million in 2016, $0.6 million in 2015 and $0.6 million in 2014 for Consolidated SCE&G. At December 31, 2016, unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months, was $23.4 million for the Company and $17.2 million for Consolidated SCE&G.
10. COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of 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 SCE&G’s nuclear power plant. Price-Anderson provides funds up to $13.4 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 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 insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. 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 of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at 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's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.
New Nuclear Construction
SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium in 2008 for the design and construction of the New Units. SCE&G's current ownership share in the New Units is 55%. As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.
EPC Contract and BLRA Matters
The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Estimated operating costs, including the depreciation of the utility plant costs, are then to be recovered through rates beginning when the construction of each New Unit is completed and placed into service. The BLRA also provides that, in the event of abandonment prior to plant completion, construction work in progress costs incurred, including AFC, and a return on those costs may be recoverable through rates, so long as SCE&G demonstrates by a preponderance of the evidence that its decision to abandon the New Unit(s) was prudent. As of December 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $4.5 billion, for which the financing costs on $3.8 billion have been reflected in rates under the BLRA. See Note 2 for a description of rate changes which have occurred under the BLRA.
The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. The Consortium has experienced delays throughout much of the project to date, and forecasted work crew efficiency and productivity metrics have not been met. In response, in November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. Some of these increased costs were the result of the schedule delays and were the subject of dispute.
October 2015 Amendment and WEC's Engagement of Fluor
On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor as a subcontracted construction manager.
Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an irrevocable option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion
being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016.
The October 2015 Amendment:
(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium,
(ii) revised the contractual guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively,
(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit),
(iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,
(v) provided for development of a revised construction milestone payment schedule,
(vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project,
(vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19, and
(viii) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project.
As part of its responsibility as a subcontracted construction manager, Fluor has reviewed and assisted in the development of an updated integrated project schedule which reflects WEC’s revised estimated completion dates of April 2020 and December 2020 for Units 2 and 3, respectively. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there is substantial uncertainty as to WEC’s ability to meet these dates given its historical inability to achieve forecasted productivity and work force efficiency levels.
November 2016 SCPSC Order
In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. See also Note 2.
The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million. SCE&G’s total project capital cost is now estimated at approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25%. This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time.
On December 14, 2016, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement. These parties may appeal this decision to the South Carolina Supreme Court once the SCPSC’s order has been issued. SCE&G cannot determine when the SCPSC will issue its order in this matter or if that order will be appealed.
Construction Milestone Payment Schedule and Related DRB Activity
The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties, and amounts in dispute of less than $5 million will be resolved by the DRB without recourse. Amounts in dispute greater than $5 million will be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.
On December 2, 2016 the DRB issued an order establishing a construction milestone payment schedule (see (v) in October 2015 Amendment above) on which SCE&G and WEC had been unable to agree subsequent to the October 2015 Amendment. The dispute related only to the timing of payments; the total amount to be paid was not in dispute. The DRB order provides that certain subcontractor and other supplier-related costs incurred by the Consortium will be reimbursed by the owners regardless of payment-milestone completion, but that other payments will be made only upon documented achievement of the agreed-upon payment-milestones. Such subcontractor and other supplier-related costs comprised approximately $873 million of the $3.345 billion of fixed option payments that were the subject of the DRB order.
Payment and Performance Obligations and Certain Related Uncertainties
Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15% of the highest projected three months billings during the applicable year, and their aggregate nominal coverage will not exceed $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds.
In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G has obtained standby letters of credit in lieu of payment and performance bonds from WEC totaling $45 million (or approximately $25 million for SCE&G's 55% share). These standby letters of credit expire annually in February, and they automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, and certain intellectual property and software have been deposited. Additional deposits are anticipated.
In December 2016 through February 2017, Toshiba and WEC announced further deterioration in their financial position and liquidity related to write-downs arising from WEC’s acquisition of Stone and Webster from CB&I (discussed above). The announcements noted that WEC and Toshiba have determined that significant losses will be incurred under the EPC Contract for the New Units and under a similar engineering, procurement and construction agreement for other units currently being constructed in the United States. This determination has impacted their allocation of the CB&I purchase price, resulting in recognition of a large amount of goodwill which has in turn been determined to be impaired. Preliminary recognition of this impairment loss (in excess of $6 billion) has left Toshiba with negative shareholders' equity and threatened its liquidity. In January 2017, Toshiba’s credit ratings were further reduced. In response, Toshiba has indicated its interest in monetizing portions of its business as it attempts to restructure and restore its financial position. Toshiba has also indicated that it will withdraw from the nuclear construction business prospectively and that it will significantly alter its risk management oversight of its nuclear power business. WEC has told the Company that it and Toshiba are committed to completing the New Units. Toshiba has acknowledged its parental guaranty to the project, but it has informed the Company that no specific commitment regarding completion of the New Units has been agreed to by it so far.
Toshiba also announced that it had requested (and successfully received) a one-month extension of the deadline for submitting its securities report to Japanese securities regulators for the quarter ended December 31, 2016 to allow an internal investigation into the adequacy of internal controls relating to the purchase price allocation process for WEC’s acquisition of Stone & Webster and concerns that senior management at WEC may have exerted inappropriate pressure in order to advance the purchase price allocation process. As part of the announcement, it was stated that Toshiba’s audit committee was concerned that an invalidation of internal controls (or even the possibility thereof) might affect Toshiba’s quarterly financial
statements, and that two law firms had been separately retained by the audit committee and WEC to assist with this investigation.
Although progress on the project was seen in December 2016 and January 2017, including the placement of the first of Unit 2’s two steam generators, significant risks and uncertainties remain concerning WEC’s ability to improve work force efficiency and productivity performance and to continue to fulfill its performance and financial commitments and Toshiba's ability to perform under its payment guaranty with respect to the project. In particular, there can be no assurance that their creditors will continue to provide support or that other sources of liquidity will emerge or continue to be available. In the event that WEC were to fail to complete the project in breach of its obligations under the EPC Contract, its payment obligations for damages would increase substantially above the amount of the liquidated damages described above, but would still be subject to limitations.
SCE&G and Santee Cooper, the co-owner of the New Units, continue to evaluate various actions which might be taken in the event that Toshiba and WEC are unable or unwilling to complete the project. These include completing the work under possible arrangements with other contractors or, were it determined to be prudent, halting the project and leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA.
Also, in response to these developments and in light of the DRB-established construction milestone payment schedule, in February 2017, SCE&G initiated its solicitation for increased levels of standby letters of credit in lieu of payment and performance bonds referred to above. However, it is uncertain whether such additional levels of standby letters of credit will be available at reasonable cost or whether any letters of credit will continue to be renewed by their issuers.
Finally, additional claims by the Consortium or SCE&G involving the project schedule, budget and performance may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues, and SCE&G expects to resolve disputes through those means. SCE&G expects to seek recovery through rates of any project costs that arise through such dispute resolution processes, as well as other project costs identified from time to time; however, any such request would be subject to the provisions of the November 2016 SCPSC order discussed above. There can be no assurance that recovery would be granted.
Santee Cooper Matters
As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s current projected cost for the additional 5% interest being acquired from Santee Cooper is approximately $850 million.
Nuclear Production Tax Credits
The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the recently revised forecasted dates of completion) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations and Certain Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.
Other Project Matters
When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.
Environmental
The Company's 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. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions.
From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the SO2 and NOX emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in 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. These actions are expected to address many of the rules and regulations discussed herein.
On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO2 from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO2 per MWh and new natural gas units to meet 1,000 pounds CO2 per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future.
In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national CO2 emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives each state from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.
In July 2011, the EPA issued the CSAPR to reduce emissions of SO2 and NOX from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO2 emissions and annual and ozone season NOX emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO2 and NOX and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.
In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.
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 state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January
4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. The Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.
The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates.
The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future 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, and it 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, 2016, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G may evaluate other technology as it becomes available.
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided 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 and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2018 and will cost an additional $10.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.7 million and are included in regulatory assets.
Claims and Litigation
The Company and Consolidated SCE&G are subject to various claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows or financial condition.
Operating Lease Commitments
The Company and Consolidated SCE&G are obligated under various operating leases for land, office space, furniture, vehicles, equipment, rail cars, a purchase power agreement, and for the Company, airplanes. Leases expire at various dates through 2057.
Rent Expense
Millions of dollars
The Company
$
10.2
$
11.1
$
12.3
Consolidated SCE&G
12.2
12.3
12.1
Future Minimum Rental Payments
Millions of dollars
Thereafter
The Company
$
$
$
$
$
$
Consolidated SCE&G
-
Guarantees
SCANA 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. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA 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, 2016, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $1.7 billion.
Asset Retirement Obligations
A liability for the present value of an ARO is recognized when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations. As of December 31, 2016, SCE&G has recorded AROs of approximately $199 million for nuclear plant decommissioning (see Note 1). In addition, the Company has recorded AROs of approximately $359 million, including $323 million for Consolidated SCE&G, for other conditional obligations primarily related to other generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of precision, particularly since such payments will be made many years in the future.
A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows:
The Company
Consolidated SCE&G
Millions of dollars
Beginning balance
$
$
$
$
Liabilities incurred
-
-
-
-
Liabilities settled
(11
)
(16
)
(11
)
(16
)
Accretion expense
Revisions in estimated cash flows
(52
)
(55
)
Ending balance
$
$
$
$
Revisions in estimated cash flows in 2016 primarily related to changes in projected costs, based on a nuclear decommissioning cost study. Such revisions in 2015 related to changes in the expected timing of ARO settlements due to changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.
11. AFFILIATED TRANSACTIONS
The Company:
The Company received cash distributions from equity-method investees of $3.7 million in 2016, $4.0 million in 2015 and $7.8 million in 2014. The Company made investments in equity-method investees of $5.5 million in 2016, $4.1 million in 2015 and $5.7 million in 2014.
The Company and Consolidated SCE&G:
SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. Consolidated SCE&G’s total purchases from this affiliate were $161.8 million in 2016, $233.2 million in 2015 and $260.3 million in 2014. Consolidated SCE&G’s total sales to this affiliate were $160.8 million in 2016, $232.0 million in 2015 and $259.0 million in 2014. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s payable to this affiliate was $16.1 million at December 31, 2016 and $12.9 million at December 31, 2015. Consolidated SCE&G’s receivable from this affiliate was $16.0 million at December 31, 2016 and $12.8 million at December 31, 2015.
Consolidated SCE&G:
SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $111.5 million in 2016, $128.5 million in 2015 and $195.7 million in 2014. SCE&G’s payables to SCANA Energy for such purchases were $8.8 million and $7.5 million as of December 31, 2016 and 2015, respectively.
SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services, including amounts capitalized, totaled $337.7 million in 2016, $300.0 million in 2015 and $292.2 million in 2014. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the consolidated statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were $63.5 million and $57.0 million at December 31, 2016 and 2015, respectively.
Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. SCE&G's purchases from CGT totaled approximately $3.4 million in 2015 and $30.0 million in 2014.
Borrowings from and investments in an affiliated money pool are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.
12. SEGMENT OF BUSINESS INFORMATION
Reportable segments, which are described below, follow the same accounting policies as those described in Note 1 and reflect the effect of certain reclassifications described therein. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast.
All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 1) and their operating
results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented.
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. Gas Marketing operates in a deregulated environment.
Management uses operating income to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense or assets other than utility plant. For nonregulated operations, management uses net income as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated 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 net income consist of the unallocated net income of regulated reportable segments.
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 amounts 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 AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.
Reportable segments have changed from what was reported as of December 31, 2015 to combine the former Retail Gas Marketing and Energy Marketing segments into a single Gas Marketing segment. This change in reportable segments occurred due to changes in the structure of the Company’s internal organization which included the integration of strategic planning and reporting for these business units and the related integration of the chief operating decision maker’s assessment of performance and resource allocation. Corresponding amounts in prior periods have been revised to conform to the current presentation.
Disclosure of Reportable Segments
The Company:
Millions of dollars
Electric
Operations
Gas
Distribution
Gas
Marketing
All
Other
Adjustments/
Eliminations
Consolidated
Total
External Revenue
$
2,614
$
$
-
-
$
4,227
Intersegment Revenue
$
$
(532
)
-
Operating Income
n/a
-
1,153
Interest Expense
-
Depreciation and Amortization
(16
)
Income Tax Expense
-
Net Income (Loss)
n/a
n/a
(18
)
Segment Assets
11,929
2,892
1,124
2,532
18,707
Expenditures for Assets
1,275
1,579
Deferred Tax Assets
-
(52
)
-
External Revenue
$
2,551
$
$
1,018
$
$
(4
)
$
4,380
Intersegment Revenue
(549
)
-
Operating Income
n/a
1,308
Interest Expense
Depreciation and Amortization
(14
)
Income Tax Expense
Net Income
n/a
n/a
Segment Assets
10,883
2,606
2,458
17,146
Expenditures for Assets
1,087
(154
)
1,153
Deferred Tax Assets
-
(49
)
-
External Revenue
$
2,622
$
1,012
$
1,301
$
$
(21
)
$
4,951
Intersegment Revenue
(642
)
-
Operating Income
n/a
1,007
Interest Expense
Depreciation and Amortization
(14
)
Income Tax Expense
Net Income (Loss)
n/a
n/a
(6
)
Segment Assets
10,182
2,487
1,474
2,385
16,818
Expenditures for Assets
(98
)
1,092
Deferred Tax Assets
(75
)
-
Consolidated SCE&G:
Millions of dollars
Electric
Operations
Gas
Distribution
Adjustments/
Eliminations
Consolidated
Total
External Revenue
$
2,619
$
-
$
2,986
Operating Income
-
1,013
Interest Expense
-
$
Depreciation and Amortization
(13
)
Segment Assets
11,929
3,337
16,091
Expenditures for Assets
1,275
1,399
Deferred Tax Assets
n/a
(9
)
-
External Revenue
$
2,557
$
-
$
2,930
Operating Income
-
Interest Expense
-
$
Depreciation and Amortization
(11
)
Segment Assets
10,883
3,125
14,765
Expenditures for Assets
1,087
(136
)
1,008
Deferred Tax Assets
n/a
(5
)
-
External Revenue
$
2,629
$
-
$
3,091
Operating Income
-
Interest Expense
-
$
Depreciation and Amortization
(12
)
Segment Assets
10,182
3,175
14,078
Expenditures for Assets
(57
)
Deferred Tax Assets
n/a
(11
)
-
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company
Millions of dollars, except per share amounts
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Annual
Total operating revenues
$
1,172
$
$
1,093
$
1,057
$
4,227
Operating income
1,153
Net income
Earnings per share
1.23
.74
1.32
.87
4.16
Total operating revenues
$
1,389
$
$
1,068
$
$
4,380
Operating income
1,308
Net income
Earnings per share
2.80
.69
1.04
.69
5.22
Consolidated SCE&G
Millions of dollars
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Annual
Total operating revenues
$
$
$
$
$
2,986
Operating income
1,013
Net Income
Earnings Available to Common Shareholder
Total operating revenues
$
$
$
$
$
2,930
Operating income
Net Income
Earnings Available to Common Shareholder
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, 2016, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based on this evaluation, the CEO and CFO concluded that, as of December 31, 2016, SCANA's disclosure controls and procedures were effective.
Management’s Evaluation of Internal Control Over Financial Reporting:
As of December 31, 2016, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any change in SCANA's internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2016. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2016 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.
The Management Report on Internal Control over Financial Reporting 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 its 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, 2016. 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 (2013). Based on this assessment, SCANA’s management believes that, as of December 31, 2016, 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, 2016, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) 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, 2016, of the Company and our report dated February 24, 2017, expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 24, 2017
SCE&G:
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2016, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based on this evaluation, the CEO and CFO concluded that, as of December 31, 2016, SCE&G's disclosure controls and procedures were effective.
Management’s Evaluation of Internal Control Over Financial Reporting:
As of December 31, 2016, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any change in SCE&G's internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2016. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2016 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.
The Management Report on Internal Control over Financial Reporting 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 its 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, 2016. 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 (2013). Based on this assessment, SCE&G’s management believes that, as of December 31, 2016, internal control over financial reporting is effective based on those criteria.
ITEM 9B. OTHER INFORMATION
SCANA:
The following information is included herein in lieu of filing it in Item 1.01 of Form 8-K:
On February 22, 2017, consistent with its past practice, SCANA entered into an indemnification agreement with Randal M. Senn in connection with his promotion in 2016.
The indemnification agreement generally provides that SCANA will indemnify the covered person for claims arising in such person's capacity as a director, officer, employee or other agent of SCANA or its subsidiaries, provided that, among other things, such person acted in good faith and with a view to the best interests of SCANA and, with respect to any criminal proceeding, had no reasonable grounds for believing that person's conduct was unlawful. The indemnification agreement also provides for payment for or reimbursement of reasonable expenses incurred by an indemnitee who is a party to a proceeding in advance of final disposition of the proceeding under certain circumstances.
The above description of the indemnification agreement is qualified in its entirety by reference to the form of indemnification agreement that was filed as Exhibit 10.01 to SCANA's Quarterly Report on Form 10-Q for the period ended June 30, 2012 and that is incorporated herein by reference.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
SCANA: A list of SCANA’s executive officers is in Part I of this annual report at page 23. The other information required by Item 10 is incorporated herein by reference to the captions “INFORMATION ABOUT EXPERIENCE AND QUALIFICATION OF DIRECTORS AND NOMINEES,” “NOMINEES FOR DIRECTOR,” “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 2017 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.
SCE&G: Not applicable.
ITEM 11. EXECUTIVE COMPENSATION
SCANA: The information required by Item 11 is incorporated herein by reference to the captions “Compensation Committee Interlocks and Insider Participation,” “Compensation Risk Assessment,” “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table,” “2016 Grants of Plan-Based Awards,” “Outstanding Equity Awards at 2016 Fiscal Year-End,” “2016 Option Exercises and Stock Vested,” “Pension Benefits,” “2016 Nonqualified Deferred Compensation,” and “Potential Payments Upon Termination or Change in Control,” under the heading “EXECUTIVE COMPENSATION” and the heading “DIRECTOR COMPENSATION” in SCANA’s definitive proxy statement for the 2017 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.
SCE&G: Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
SCANA: 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 2017 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, 2016 are summarized as follows:
Plan Category
Number of
securities
to be issued
upon exercise
of outstanding
options, warrants
and rights
Weighted-average
exercise price of outstanding options,
warrants
and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))
(a)
(b)
(c)
Equity compensation plans approved by security holders:
-
2015 Long-Term Equity Compensation Plan
306,428
(1)
n/a
4,963,572
Prior Long-Term Equity Compensation Plan
296,732
(2)
n/a
-
Non-Employee Director Compensation Plan
n/a
n/a
179,248
Equity compensation plans not approved by security holders
n/a
n/a
n/a
Total
603,160
n/a
5,142,820
(1) Represents unearned non-vested performance share awards from the 2015-2017 and 2016-2018 performance periods assuming a target level payout.
(2) Represents performance shares related to vested grants from the 2014-2016 performance period which were settled in cash rather than shares in February 2017.
SCE&G: Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
SCANA: The information required by Item 13 is incorporated herein by reference to the captions “RELATED PARTY TRANSACTIONS” and “GOVERNANCE INFORMATION - Director Independence” in SCANA’s definitive proxy statement for the 2017 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.
SCE&G: Not applicable.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
SCANA: The information required by Item 14 is incorporated herein by reference to “PROPOSAL 4-APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in SCANA’s definitive proxy statement for the 2017 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, 2016 and 2015 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.
Audit Fees (1)
$
2,316,288
$
2,032,222
Audit-Related Fees (2)
117,146
114,832
Total Fees
$
2,433,434
$
2,147,054
(1) Fees for audit services billed in 2016 and 2015 consisted of audits of annual financial statements, comfort letters for securities underwriters, statutory and regulatory audits, consents and other services related to SEC filings, and accounting research.
(2) Fees primarily for employee benefit plan audits and non-statutory audit services.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed or furnished as a part of this Form 10-K:
(1) Financial Statements and Schedules:
The Report of Independent Registered Public Accounting Firm on the financial statements for each of SCANA and SCE&G is 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 "Schedule II - Valuation and Qualifying Accounts" 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
Additions
Description (in millions)
Beginning
Balance
Charged to
Income
Charged to
Other
Accounts
Deductions
from
Reserves
Ending
Balance
SCANA:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
$
$
-
$
$
-
-
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
$
$
-
$
$
-
-
SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
$
$
-
$
$
-
-
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
$
$
-
$
$
-
-
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 24, 2017
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
Vice President and Controller
(Principal Accounting Officer)
Other Directors*:
G. E. Aliff
J. M. Micali
J. A. Bennett
L. M. Miller
J. F. A. V. Cecil
J. W. Roquemore
S. A. Decker
M. K. Sloan
D. M. Hagood
A. Trujillo
* Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
DATE: February 24, 2017
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 24, 2017
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
Vice President and Controller
(Principal Accounting Officer)
Other Directors*:
G. E. Aliff
J. M. Micali
J. A. Bennett
L. M. Miller
J. F. A. V. Cecil
J. W. Roquemore
S. A. Decker
M. K. Sloan
D. M. Hagood
A. Trujillo
* Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
DATE: February 24, 2017
EXHIBIT INDEX
Exhibit
Applicable to
Form 10-K of
No.
SCANA
SCE&G
Description
3.01
X
Restated Articles of Incorporation of SCANA, 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 SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File No. 000-53860) and incorporated by reference herein)
3.05
X
By-Laws of SCANA as amended and restated as of December 30, 2016 (Filed herewith)
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 SCE&G and SCANA (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 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 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
Indenture dated as of April 1, 1993 from SCE&G 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)
4.05
X
First Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)
4.06
X
Second Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)
4.07
X
Third Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of September 1, 2013 (Filed as Exhibit 4.12 to Post-Effective Amendment to Registration Statement No. 333-184426-01 and incorporated by reference herein)
10.01
X
X
Engineering, Procurement and Construction Agreement, dated May 23, 2008, between SCE&G, 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 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.02
X
X
Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and SCE&G 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 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.03
X
X
Amendment to EPC Contract referred to in Exhibit 10.01 dated October 27, 2015 (Filed as Exhibit 10.05 to Form 10-Q for the quarter ended September 30, 2015 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
*10.04
X
X
SCANA Executive Deferred Compensation Plan (including amendments through November 25, 2014) (Filed as Exhibit 10.03 to Form 10-K for the year ended December 31, 2014 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
*10.05
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)
*10.06
X
X
SCANA Director Compensation and Deferral Plan (including amendments through November 30, 2014) (Filed as Exhibit 10.05 to Form 10-K for the year ended December 31, 2014 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
*10.07
X
X
SCANA Long-Term Equity Compensation Plan effective February 19, 2015 (Filed as Exhibit 4.05 to Registration Statement No. 333-204218 and incorporated by reference herein)
*10.08
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)
*10.09
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)
*10.10
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)
*10.11
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 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.12
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)
10.13
X
Form of Indemnification Agreement (Filed as Exhibit 10.01 to Form 10-Q dated June 30, 2012 (File No. 001-08809) and incorporated by reference herein)
10.14
X
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among SCANA; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Morgan Stanley Bank, N.A., as Issuing Bank; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.1 to Form 8-K on December 22, 2015 (File No. 001-08809) and incorporated by reference herein)
10.15
X
X
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A., as Issuing Bank and Co-Syndication Agent; Morgan Stanley Senior Funding, Inc., as Co-Syndication Agent; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.2 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.16
X
X
Amended and Restated Three-Year Credit Agreement dated as of December 17, 2015, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Swingline Lender and Agent; Morgan Stanley Bank, N.A., as Issuing Bank; Bank of America, N.A. as Issuing Bank and Co-Syndication Agent; Morgan Stanley Senior Funding, Inc., as Co-Syndication Agent; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.3 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.17
X
X
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among Fuel Company; the lenders identified therein; Wells Fargo Bank, National Association, as Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.4 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.18
X
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among PSNC Energy; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.5 to Form 8-K on December 22, 2015 (File No. 001-08809) and incorporated by reference herein)
12.01
X
X
Statement Re Computation of Ratios (Filed herewith)
21.01
X
Subsidiaries of the registrant (Filed herewith)
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 and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02
X
Certification of Principal Executive Officer and 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.