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South Carolina Electric & Gas Company Shares Outstanding 2014 SCANA Corporation Without Par Value South Carolina Electric & Gas Company Without Par Value 40,296,147 Documents incorporated by reference: Specified sections of SCANA Corporation’s Proxy Statement, in connection with its the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment; regulatory actions, particularly changes in rate regulation, regulations governing electric grid reliability and pipeline integrity, environmental regulations, and actions affecting the construction of new nuclear units; current and future litigation; changes in the economy, especially in areas served by subsidiaries of SCANA; the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets; the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity; the effects of weather, payment and performance by counterparties and customers as contracted and when due; the results of efforts to license, site, construct and finance facilities for electric generation and transmission; maintaining creditworthy joint owners for SCE&G’s new nuclear generation project; the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components, parts, tools, equipment and other supplies needed, at agreed upon prices, for our construction program, operations and maintenance; the results of efforts to ensure the physical and cyber security of key assets and processes; the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels and purchased power; and the ability to recover the costs for such fuels and purchased power; the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s businesses; performance of SCANA’s pension plan assets; changes in taxes; inflation or deflation; compliance with regulations; natural disasters and man-made mishaps that directly affect our operations or the regulations governing them; and the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or SCE&G with the SEC. DEFINITIONS Abbreviations used in this Form 10-K have the meanings set forth below unless the context requires otherwise: MEANING ANI American Nuclear Insurers Accumulated Other Comprehensive Income BACT Best Available Control Technology BLRA Base Load Review Act CAA Clean Air Act, as amended CAIR Clean Air Interstate Rule Coal Combustion Residuals CEO Chief Executive Officer CFO Chief Financial Officer Commodity Futures Trading Commission CGT Carolina Gas Transmission Corporation COL Combined Construction and Operating License Company SCANA, together with its consolidated subsidiaries Consolidated SCE&G SCE&G and its consolidated affiliates Consortium A consortium consisting of Westinghouse Electric Company LLC and Stone and Webster, Inc., a subsidiary of CSAPR Cross-State Air Pollution Rule CUT Customer Usage Tracker CWA Clean Water Act DHEC South Carolina Department of Health and Environmental Control Dodd-Frank Dodd-Frank Wall Street Reform and Consumer Protection Act DOE United States Department of Energy DOJ United States Department of Justice United States Department of Transportation DSM Programs Demand Side Management Programs EIZ Credits South Carolina Capital Investment Tax Credits (formerly known as Economic Impact Zone Income Tax Credits) ELG Rule The divisions of SEMI, excluding SCANA Energy EPA United States Environmental Protection Agency EPC Contract Engineering, Procurement and Construction Agreement dated May 23, 2008 eWNA Pilot Electric WNA FERC United States Federal Energy Regulatory Commission Fuel Company South Carolina Fuel Company, Inc. GENCO South Carolina Generating Company, Inc. GHG Greenhouse Gas GPSC Georgia Public Service Commission GWh Gigawatt hour Integrated Resource Plan LOC Lines of Credit MATS Mercury and Air Toxics Standards MCF or MMCF Thousand Cubic Feet or Million Cubic Feet MGP Manufactured Gas Plant MMBTU Million British Thermal Units MW or MWh Megawatt or Megawatt-hour NASDAQ The NASDAQ Stock Market, Inc. North Carolina Utilities Commission NERC North American Electric Reliability Corporation New Units Nuclear Units 2 and 3 United States Nuclear Regulatory Commission New Source Performance Standards Nuclear Waste Act Nuclear Waste Policy Act of 1982 NYMEX New York Mercantile Exchange NYSE The New York Stock Exchange OCI Other Comprehensive Income ORS South Carolina Office of Regulatory Staff PGA Purchased Gas Adjustment United States Pipeline Hazardous Materials Safety Administration Price-Anderson Indemnification Act PRP Potentially Responsible Party PSNC Energy Public Service Company of North Carolina, Incorporated RCC Replacement Capital Covenant Natural Gas Rate Stabilization Act Santee Cooper South Carolina Public Service Authority SCANA SCANA Corporation, the parent company SCANA Energy A division of SEMI which markets natural gas in Georgia SCE&G South Carolina Electric & Gas Company SCEUC South Carolina Energy Users Committee SCI SCANA Communications, Inc. SCPSC Public Service Commission of South Carolina United States Securities and Exchange Commission SCANA Energy Marketing, Inc. SERC Southern Natural Gas Company Summer Station V. C. Summer Nuclear Station TSR Total Shareholder Return Virginia-Carolinas Reliability Group VIE Variable Interest Entity Westinghouse Westinghouse Electric Company LLC Williams Station A.M. Williams Generating Station, owned by GENCO WNA Weather Normalization AdjustmentIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.SCANA Corporation x South Carolina Electric & Gas Company xIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.SCANA Corporation o South Carolina Electric & Gas Company oIndicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. SCANA Corporation Yes x No o South Carolina Electric & Gas Company Yes x No oIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).SCANA Corporation Yes x No o South Carolina Electric & Gas Company Yes x No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. SCANA Corporation ox South Carolina Electric & Gas Company xIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Exchange Act Rule 12b-2).SCANA Corporation Large accelerated filer x
Accelerated filer oNon-accelerated filer oSmaller reporting company oAccelerated filer oNon-accelerated filer o(Do not check if a smaller reporting company)Large accelerated filer o
Accelerated filer oNon-accelerated filer xSmaller reporting company oAccelerated filer oNon-accelerated filer x(Do not check if a smaller reporting company)Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).SCANA Corporation Yes o No x South Carolina Electric & Gas Company Yes o No xThe aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $5.0$6.85 billion at June 30, 201128, 2013, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price of $39.37$49.10 per share. South Carolina Electric & Gas Company is a wholly-ownedwholly‑owned subsidiary of SCANA Corporation and has no voting stock other than its common stock.stock, all of which is held beneficially and of record by SCANA Corporation. A description of registrants’ common stock follows:RegistrantRegistrant Description of
Common Stock
at February 20, 2012130,295,890141,144,841 (a)(a)Held beneficially and of record by SCANA Corporation.20122014 Annual Meeting of Shareholders, are incorporated by reference in Part III hereof.This combined Form 10-K is separately filed by SCANA Corporation and South Carolina Electric & Gas Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other company.South Carolina Electric & Gas Company meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and therefore is filing this Form with the reduced disclosure format allowed under General Instruction I (2)I(2).PagePage 6152122242526272829901411411431441441441441451461481502Statements included in this Annual Report on Form 10-K which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include, but are not limited to, statements concerning key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “forecasts,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:(1)(1) (2) (2)(3) (3)(4) (4)(5) (5)(6) the impact of conservation and demand side management efforts and/or technological advances on customer usage; (6)the loss of sales to distributed generation, such as solar photovoltaic systems; (8) growth opportunities for SCANA’s regulated and diversified subsidiaries; (9) (7)(10) (8)changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;(9) including drought, especially in areas where the generation and transmission facilities of SCANA and its subsidiaries (the Company) are located and in areas served by SCANA’s subsidiaries;(11) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies; (10)(13) (11)(14) (12)(15) (13)(16) (14)(17) (15)(18) (16)(19) labor disputes; (17)labor disputes;(18)(21) (19)(22) (20)(23) (21)(24) (22)(25) (23)SCANA and SCE&G disclaim any obligation to update any forward-looking statements.3Table of ContentsTERMMEANINGAERAlternate Energy Resources, Inc.AFCAFC Allowance for Funds Used During Construction AROARO Asset Retirement Obligation CAMRClean Air Mercury RuleCCRCERCLACERCLA Comprehensive Environmental Response, Compensation and Liability Act The Shaw Group, Inc.DominionDominion Transmission, Inc.DOTDTDekatherm (one million BTUs)DukeDuke Energy CarolinasNew federal effluent limitation guidelines for steam electric generating units Energy Marketing FEISFinal Environmental Impact StatementFSERFinal Safety Evaluation ReportIRSIRS United States Internal Revenue Service KVAKilovolt amperekW or kWhKilowatt or Kilowatt-hourLLCLimited Liability CompanyLNGTERM MEANING Level 1 A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities Level 2 A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means Level 3 A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability LNG Liquefied Natural Gas MACTMaximum Achievable Control TechnologyTERMMEANINGNEILNEIL Nuclear Electric Insurance Limited to be constructedunder construction at Summer StationNCUCNorth Carolina Utilities CommissionNMSTNegotiated Market Sales TariffNRCNSRNSR New Source Review Pipeline Safety ActThe Pipeline Safety Improvement Act of 2002PHMSAPlanSCANA Long-Term Equity Compensation PlanPrice-AndersonRCRAResource Conservation and Recovery ActRESRenewable Energy StandardRSASCRSelective Catalytic ReactorSECSERCSERC Reliability CorporationSEMISERC Reliability Corporation Southern Natural TranscoTERM MEANING Transco Transcontinental Gas Pipeline Corporation USACEUnited States Army Corps of EngineersVACAR54
PART I
AND ORGANIZATION Regulated Utilities construction. SCI leases fiber optic capacity, data center space and tower space to certain affiliates at market rates. CAPITAL REQUIREMENTS as follows: Sales Margins Customer Classification 2010 2011 2010 2011 Residential 43 % 43 % 48 % 48 % Commercial 32 % 32 % 33 % 33 % Industrial 17 % 17 % 13 % 13 % Sales for resale 6 % 6 % 4 % 4 % Other 2 % 2 % 2 % 2 % Total Territorial 100 % 100 % 100 % 100 % NMST — % — % — % — % Total 100 % 100 % 100 % 100 % Electric Interconnections Cost of Fuel Used 2009 2010 2011 Per MMBTU: Nuclear $ .48 $ .72 $ .88 Coal 4.36 4.49 4.47 Natural Gas 4.61 5.48 4.86 All Fuels (weighted average) 3.61 3.80 3.80 Per Ton: Coal 108.39 110.63 109.91 Per thousand cubic feet (MCF): Gas 4.81 5.64 5.01 % of Total MWh Generated Actual Estimated 2009 2010 2011 2012 2013 2014 Coal 51 % 52 % 50 % 46 % 44 % 46 % Nuclear 18 % 21 % 19 % 20 % 22 % 20 % Hydro 4 % 4 % 3 % 4 % 4 % 4 % Natural Gas & Oil 27 % 23 % 28 % 29 % 29 % 29 % Biomass — — — 1 % 1 % 1 % Total 100 % 100 % 100 % 100 % 100 % 100 % SCE&G completed the retirement of one of these plants (comprised of three units) in 2012 and 2013 and intends to retire certain other coal-fired generating units by 2018, subject to future developments in environmental regulations, among other matters. One of the units to be retired by 2018 was fueled with coal prior to 2013, but is expected to be fueled exclusively with natural gas until its retirement. Those new agreements may, but will not necessarily, be between SCE&G and the Consortium. SCANA SCE&G Customer Classification 2010 2011 2010 2011 Residential 56.1 % 54.5 % 45.7 % 43.4 % Commercial 27.2 % 27.2 % 28.8 % 28.6 % Industrial 11.6 % 12.5 % 22.0 % 23.9 % Transportation Gas 5.1 % 5.8 % 3.5 % 4.1 % Total 100.0 % 100.0 % 100.0 % 100.0 % 82,615 MMBTU. 2012. 2013. Transco. 2012. 2013. 2014. 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. Fuel Cost Recovery Procedures time. SCPSC proceedings related to SCE tariffs are described in Note 2 to the consolidated financial statements for SCANA and SCE&G. PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. statements for SCANA. 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. gas from the Company and Consolidated SCE&G. Furthermore, issued or what requirements they will impose. electric generating units. Renewable and/or alternative electric generation portfolio standards may be enacted at the federal or state level. Some states already have them, though currently South Carolina does not. Such standards could direct us to build or otherwise acquire generating capacity derived from renewable/alternative energy sources (generally, renewable energy such as biomass, solar, wind and tidal, and excluding fossil fuels, nuclear or hydro facilities). Such renewable/alternative energy may not be readily available in our service territories, if at all, and could be extremely costly to build, acquire, and operate. Resulting increases in the price of electricity to recover the cost of these types of generation, if approved by regulatory commissions, impaired. Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed. Insurance may not be available or adequate to respond to these events. Facility Present Location Year Net Generating Steam Turbines: Summer(1) Nuclear Jenkinsville, SC 1984 644 McMeekin Coal/Gas Irmo, SC 1958 250 Canadys Coal/Gas Canadys, SC 1962 385 Wateree Coal Eastover, SC 1970 684 Williams(2) Coal Goose Creek, SC 1973 605 Cope Coal Cope, SC 1996 415 Kapstone(3) Biomass/Coal Charleston, SC 1999 85 Combined Cycle: Urquhart(4) Coal/Gas/Oil Beech Island, SC 1953/2002 553 Jasper Gas/Oil Hardeeville, SC 2004 869 Hydro(5): Saluda Irmo, SC 1930 200 Fairfield Pumped Storage Jenkinsville, SC 1978 576 385 MW) and are not included in the table above. Another unit, Urquhart Unit 3, was fueled with coal prior to 2013, and is expected to be fueled with natural gas until its retirement in 2018. Spartanburg counties in South Carolina. PSNC Energy owns, through a wholly-owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina. SCANA and SCE&G are Age Dates Kevin B. Marsh Officer-SCANA Jimmy E. Addison Jeffrey B. Archie George J. Bullwinkel Sarena D. Burch Stephen A. Byrne Paul V. Fant W. Keller Kissam Ronald T. Lindsay Senior Vice President, General Counsel and Assistant Secretary Charles B. McFadden Martin K. Phalen PART IICORPORATE STRUCTURESCANA, a holding company, owns the following direct, wholly-owned subsidiaries:SCE&G is engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers and the purchase, sale and transportation of natural gas to retail customers.GENCO owns Williams Station and sells electricity solely to SCE&G.Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances.PSNC Energy purchases, sells and transports natural gas to retail customers.CGT transports natural gas in South Carolina and southeastern Georgia.SCI provides fiber optic communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia.SEMI markets natural gas, primarily in the Southeast, and provides energy- related risk management services. SCANA Energy, a division of SEMI, markets natural gas in Georgia’s retail market.ServiceCare, Inc. provides service contracts on home appliances and heating and air conditioning units.SCANA Services, Inc. provides administrative, management and other services to SCANA’s subsidiaries and business units.SCANA is incorporated in South Carolina, as is each of its direct, wholly- owned subsidiaries. In addition to the subsidiaries above, SCANA owns two other energy-related companies that are insignificant.SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA holds directly or indirectly, all of the capital stock of the following subsidiaries, each of its subsidiaries. which is incorporated in South Carolina.SCE&G Engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers and the purchase, sale and transportation of natural gas to retail customers GENCO Owns Williams Station and sells electricity solely to SCE&G Fuel Company Acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances PSNC Energy Purchases, sells and transports natural gas to retail customers CGT Transports natural gas in South Carolina and southeastern Georgia SCI Provides fiber optic communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia SEMI Markets natural gas, primarily in the Southeast, and provides energy‑related risk management services. SCANA Energy, a division of SEMI, markets natural gas in Georgia’s retail market. ServiceCare, Inc. Provides service contracts on home appliances and heating and air conditioning units SCANA Services, Inc. Provides administrative, management and other services to SCANA’s subsidiaries and business units SCANA owns one other energy‑related company that is insignificant and being liquidated.SCANA and its subsidiaries had full-time, permanent employees as of February 20, 20122014 and 20112013 of 5,8895,989 and 5,877,5,842, respectively. SCE&G is an operating public utility incorporated in 1924 as a South Carolina corporation. SCE&G had full-time, permanent employees as of February 20, 2012 and 2011 of 3,202 and 3,173, respectively.INVESTOR INFORMATIONSCANA’s and SCE&G’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with or furnished to the SEC are available free of charge through SCANA’s internet website at www.scana.com (which is not intended as an active hyperlink) as soon as reasonably practicable after these reports are filed or furnished. Information on SCANA’s website is not part of this or any other report filed with or furnished to the SEC.SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s new nuclear project on SCANA’s website at www.scana.com (which is not intended to be 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). On SCANA’s homepage, there is a yellow box containing a link to the New Nuclear Development section of the website. That section in turn contains a yellow box with a link to recent project news and updates. 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, and investors, media and others interested in SCE&G’s new nuclear project are encouraged to review this information.SEGMENTS OF BUSINESSFor information with respect to major segments of business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 12). All such information is incorporated herein by reference.SCANA does not directly own or operate any significant physical properties. SCANA, through its subsidiaries, is engaged in the functionally distinct operations described below.5SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 664,000678,000 customers and the purchase, sale and transportation of natural gas to approximately 317,000329,000 customers (each as of December 31, 2011)2013). SCE&G’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 22,600 square miles. More than 3.2 million persons live in the counties where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries served by SCE&G include chemicals, educational services, paper products, food products, lumber and wood products, health services, textile manufacturing, rubber and miscellaneous plastic products and fabricated metal products.GENCO owns Williams Station and sells electricity solely to SCE&G.Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances.PSNC Energy purchases, sells and transports natural gas to approximately 487,000509,000 residential, commercial and industrial customers (as of December 31, 2011)2013). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The predominant industries served by PSNC Energy include educational services, food products, health services, automotive, chemicals, non-woven textiles, electrical generation and construction-related materials.CGT operates as an open access, transportation-only interstate pipeline company regulated by FERC. CGT operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGT also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transco in Cherokee and Spartanburg counties, South Carolina. CGT’s customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SEMI (which markets natural gas to industrial and sale for resale customers, primarily in the Southeast), municipalities, county gas authorities, federal and state agencies, marketers, power generators and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, and textiles.Nonregulated BusinessesSEMI markets natural gas primarily in the southeast and provides energy- relatedenergy-related risk management services. SCANA Energy, a division of SEMI, sells natural gas to approximately 455,000454,000 customers (as of December 31, 2011,2013, and includes approximately 80,00068,000 customers in its regulated division) in Georgia’s natural gas market. In third quarter 2013, SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas has beenwas renewed by the GPSC through August 31, 2014.2015. SCANA Energy’s total customer base represents an approximately 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in Georgia.SCI owns and operates a 500-mile1,125 mile fiber optic telecommunications network and ethernet network and data center facilities in South Carolina. Through a joint venture, SCI has an interest in an additional 2,280 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides tower site construction, management and rental services and sells towers in South Carolina and North Carolina.The preceding Corporate Structure and Organization section describes other regulated and nonregulated businesses owned by SCANA.COMPETITIONFor a discussion of the impact of competition, see the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.SCANA’s regulated subsidiaries, including SCE&G, require cash to fund operations, construction programs and dividend payments to SCANA. SCANA’s nonregulated subsidiaries require cash to fund operations and dividend payments to SCANA. To replace existing plant investment and to expand to meet future demand for electricity and gas, SCANA’s regulated subsidiaries must attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their construction programs, rate increases will be sought.6The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, when requested.For a discussion of various rate matters and their impact on capital requirements, see the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 2 to the consolidated financial statements for SCANA and SCE&G.During the period 2012-2014,2014-2016, SCANA and SCE&G expect to meet capital requirements through internally generated funds, issuance of equity and short-term and long-term borrowings. SCANA and SCE&G expect that they have or can obtain adequate sources of financing to meet their projected cash requirements for the next 12 months and for the foreseeable future.For a discussion of cash requirements for construction and nuclear fuel expenditures, contractual cash obligations, financing limits, financing transactions and other related information, see the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.SCANA’s ratiosRatios of earnings to fixed charges were 2.87, 2.92, 2.84, 3.04 and 3.03 for each of the five years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively. SCE&G’s ratios of earnings to fixed charges2013, were 3.13, 3.18, 3.25, 3.51 and 3.40 for the same periods.December 31, 2013 2012 2011 2010 2009 SCANA 3.22 2.93 2.87 2.92 2.84 SCE&G 3.48 3.29 3.13 3.18 3.25 ELECTRIC OPERATIONSElectric SalesSCE&G’s sales of electricity and margins earned from the sale of electricity by customer classification as percentages of electric revenues for 20102012 and 20112013 were as follows: Sales Margins Customer Classification 2012 2013 2012 2013 Residential 43 % 44 % 50 % 50 % Commercial 32 % 33 % 33 % 33 % Industrial 17 % 18 % 13 % 14 % Sales for resale 6 % 2 % 2 % 1 % Other 2 % 3 % 2 % 2 % Total 100 % 100 % 100 % 100 % Sales for resale include sales to three municipalities and twoone electric cooperatives. Sales under NMST during 2011 includecooperative. Short-term system sales to seven investor-owned utilities or registered marketers and three federal/state electric agencies. were not significant for any period presented.During 2010 sales under the NMST included sales to nine investor-owned utilities or registered marketers, two electric cooperatives and two federal/state electric agencies.During 20112013 SCE&G recordedexperienced a net increase of approximately 3,6008,000 electric customers (growth rate of 0.5%1.2%), increasing its total electric customers to approximately 664,000678,000 at year end.For the period 2012-2014,2014-2016, SCE&G projects total territorial KWhkWh sales of electricity to increase 0.7%0.6% annually (assuming normal weather), total retail sales growth of 0.6% annually (assuming normal weather), total electric customer base to increase 1.6%1.8% annually and territorial peak load (summer, in MW) to increase 1.0%1.9% annually. WhileSCE&G projects a retail kWh sales decrease of approximately 0.2% and customer growth of 1.1% from 2013 to 2014. SCE&G’s goal is to maintain a planning reserve margin of between 12%14% and 18%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.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.7SCE&G’s transmission system, which extends over a large part of the central, southern and southwestern portions of South Carolina, interconnects with Duke Energy Carolinas, LLC, Duke Energy Progress, Energy Carolinas,Inc., Santee Cooper, Georgia Power Company Oglethorpe Power Corporation and the Southeastern Power Administration’s Clarks Hill (Thurmond) Project. SCE&G Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Dominion Virginia Power and ALCOA Power Generating, Inc. (Yadkin Division), are membersis 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. SERC is divided geographically into five diverse sub-regions that are identified as Central, Delta, Gateway, Southeastern and VACAR. The regional entities and all members of NERC work to safeguard the reliability of the bulk power systems throughout North America. For a discussion of the impact certain legislative and regulatory initiatives may have on SCE&G’s transmission system, see Electric Operations within the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.Fuel Costs and Fuel SupplyThe average cost of various fuels and the weighted average cost of all fuels (including oil) for the years 2009-20112011-2013 follow: Cost of Fuel Used 2011 2012 2013 Per MMBTU: Nuclear $ 0.88 $ 0.94 $ 1.11 Coal 4.47 4.49 4.28 Natural Gas 4.86 3.71 4.63 All Fuels (weighted average) 3.80 3.56 3.53 Per Ton: Coal 109.91 111.72 104.63 Per MCF: Gas 5.01 3.80 4.69 The sources and percentages of total MWh generation by each category of fuel for the years 2009-20112011-2013 and the estimates for the years 2012-20142014-2016 follow:Six of % of Total MWh Generated Actual Estimated 2011 2012 2013 2014 2015 2016 Coal 50 % 50 % 45 % 50 % 49 % 45 % Nuclear 19 % 19 % 24 % 21 % 21 % 24 % Hydro 3 % 3 % 4 % 4 % 4 % 4 % Natural Gas & Oil 28 % 28 % 26 % 24 % 25 % 26 % Biomass — — 1 % 1 % 1 % 1 % Total 100 % 100 % 100 % 100 % 100 % 100 % In 2013, the sevenCompany used coal to generate electricity at six fossil fuel-fired plants, use coal.including its cogeneration facility located in Charleston, South Carolina. Unit trains and, in some cases, trucks and barges deliverdelivered coal to these plants.Coal is primarily obtained through long-term supply contracts and spot market purchases.contracts. Long-term contracts exist with suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 3.52.8 million tons annually, which is substantially all expected coal purchases for 2012.annually. Sulfur restrictions on the contract coal range from 1%1.0% to 2%1.6%. These contracts expire at various times through 2014.2016. Spot market purchases are expected to continuemay occur when needed or when prices are believed to be favorable.SCANA and SCE&G believe that SCE&G’s operations comply with all applicable regulations relating to the discharge of sulfur dioxide and nitrogen oxide. See additional discussion at Environmental Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.8On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered intoare parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, SCE&G has to supply enriched product to Westinghouse and Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. WestinghouseThe Consortium currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, andagreement. Although SCE&G has also contracted for Westinghouseprovided the Consortium with notice of its election to terminate the existing agreement, it is anticipated that SCE&G will enter into new agreements to provide similar support services to Summer Station Unit 1 and to the New Units upon their completion and commencement of commercial operation.In addition, to the above-described contracts for fuel fabrication and related services, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates in the next 11 years.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 can store spent nuclear fuel on-site until at least 2017 and expects to expand itshas commenced construction of a dry cask storage capacityfacility to accommodate the spent fuel output for the life of Summer Station Unit 1 through dry cask storage or1. SCE&G may evaluate other technology as it becomes available. In addition, Summer Station Unit 1 has sufficient on-site storage capacity to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract with the DOE regarding disposal of spent fuel, see Hazardous and Solid Wastes within the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.GAS OPERATIONSGas Sales-RegulatedRegulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 20102012 and 20112013 were as follows: SCANA SCE&G Customer Classification 2012 2013 2012 2013 Residential 54.7 % 55.6 % 44.3 % 43.5 % Commercial 26.1 % 26.0 % 27.5 % 27.4 % Industrial 11.8 % 12.5 % 22.3 % 25.6 % Transportation Gas 7.4 % 5.9 % 5.9 % 3.5 % Total 100.0 % 100.0 % 100.0 % 100.0 % For the three-year period 2012-2014,2014-2016, SCANA projects total consolidated sales of regulated natural gas in DTsMMBTUs to increase 0.9%1.4% annually (assuming(excluding transportation and assuming normal weather). Annual projected increases over such period in DTMMBTU sales include residential of 1.2%2.1%, commercial of 0.9%0.8% and industrial of 0.8%.For the three-year period 2012-2014,2014-2016, SCE&G projects total consolidated sales of regulated natural gas in DTsMMBTUs to increase 0.4%0.8% annually (assuming(excluding transportation and assuming normal weather). Annual projected increases over such period in DTMMBTU sales include residential of 0.4%1.0%, commercial of 0.3%0.6% and industrial of 1.1%1.0%.For the three-year period 2012-2014,2014-2016, SCANA’s and SCE&G’s total consolidated regulated natural gas customer base is projected to increase annually 1.5%2.3% and 1.2%1.9%, respectively. During 20112013 SCANA recorded a net increase of approximately 8,80018,000 regulated gas customers (growth rate of 1.1%2.2%), increasing its regulated gas customers to approximately 804,000.837,000. Of this increase, SCE&G recorded a net increase of approximately 3,3007,000 gas customers (growth rate of 1.1%2.1%), increasing its total gas customers to approximately 317,000329,000 (as of December 31, 2011)2013).Demand for gas changes primarily due to the effect of weather and the price relationship between gas and alternate fuels.9Gas Cost, Supply and Curtailment PlansSouth CarolinaSCE&G purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. The gas is delivered to South Carolina through firm transportation agreements with Southern Natural (expiring in 2013)2014 and 2018), Transco (expiring in 2013 and 2017) and CGT (expiring in 2012,2014, 2018, 2023 and 2026). The maximum daily volume of gas that SCE&G is entitled to transport under these contracts is 161,144 DT222,404 MMBTU from Southern Natural, 64,652 DTMMBTU from Transco and 424,429 DT425,929 MMBTU from CGT. Additional natural gas volumes may be delivered to SCE&G’s system as capacity is available through interruptible transportation.The daily volume of gas that SEMI is entitled to transport under its service agreementagreements with CGT (expiring in 2016, 2017 and 2023) on a firm basis is 78,083 DT.SCE&G purchased natural gas, including fixed transportation, at an average cost of $5.88$5.35 per MCF during 20112013 and $6.38$4.73 per MCF during 2010.SCE&G was allocated 5,4375,382 MMCF of natural gas storage capacity on the systems of Southern Natural and Transco. Approximately 4,2134,039 MMCF of gas were in storage on December 31, 2011.2013. To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCE&G supplements its supplies of natural gas with two LNG liquefaction and storage facilities. The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately 1,7591,635 MMCF (liquefied equivalent) of gas were in storage on December 31, 2011.North CarolinaPSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at currentmarket based prices and on a long-term basis for reliability assurance at first of the month index prices plus a reservation charge.charge in certain cases. Transco and Dominion deliver thetransports natural gas to North Carolina through transportation agreements with varying expiration dates ranging through 2016.2032. On a peak day, PSNC Energy may transportis capable of receiving daily transportation volumes of natural gas under these contracts, on autilizing firm basiscontracts of 281,110 DT610,062 MMBTU from Transco and 7,331 DT from Dominion.PSNC Energy purchased natural gas, including fixed transportation, at an average cost of $5.54$5.13 per DTMMBTU during 20112013 compared to $5.95$4.65 per DTMMBTU during 2010.To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and LNG peaking services. Underground natural gas storage service agreements with Dominion Transmission, Inc., Columbia Gas Transmission, Transco and Spectra Energy provide for storage capacity of approximately 13,000 MMCF. Approximately 12,00010,000 MMCF of gas were in storage under these agreements at December 31, 2011.2013. In addition, PSNC Energy’s LNG facility can store the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day. Approximately 800900 MMCF (liquefied equivalent) of gas were in storage at December 31, 2011.2013. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,2001,100 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2011.SCANA and SCE&G believe that supplies under long-term contracts and supplies available for spot market purchase are adequate to meet existing customer demands and to accommodate growth.Gas Marketing-NonregulatedSEMI markets natural gas and provides energy-related risk management services primarily in the Southeast. In addition, SCANA Energy, a division of SEMI, markets natural gas to approximately 455,000454,000 customers (as of December 31, 2011)2013) in Georgia’s natural gas market. SCANA Energy’s total customer base represents an approximate 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.Risk ManagementFor a discussion of ContentsRisk ManagementSCANA and SCE&G have establishedrisk management policies and procedures, and risk limitssee Note 6 to control the level of market, credit, liquidity and operational and administrative risks assumed by them. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and to oversee and review the risk management process and infrastructureconsolidated financial statements for SCANA and eachSCE&G.10REGULATIONFor a discussion of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including a Risk Management Officerlegislative and several senior officers, apprisesregulatory initiatives being implemented that will affect SCE&G’s transmission system, see Electric Operations within the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.REGULATIONSCANA is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters and is subject to the jurisdiction of the FERC as to certain acquisitions and other matters.SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.CGT is subject to the jurisdiction of FERC as to transportation rates, service, accounting and other matters.SCANA Energy is regulated by the GPSC through its certification as a natural gas marketer in Georgia and specifically is subject to the jurisdiction of the GPSC as to retail prices for customers served under the regulated provider contract.SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting. See the Regulatory MattersOverview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.For a discussion of the regulatory jurisdictions to which SCANA and its subsidiaries are subject, see the Regulatory Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.SCE&G and GENCO havehas obtained FERC authority to issue short-term indebtedness (pursuantand to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes, or commercial paper 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 mayhas obtained FERC authority to issue upshort-term indebtedness not to exceed $150 million outstanding with maturity dates of such short-term indebtedness.one year or less. The authority to make such issuancesdescribed herein will expire in October 2012.SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The RSA allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.SCElicenses expire as follows:Project LicenseExpirationSaluda (Lake Murray) 2014 Fairfield Pumped Storage/Parr Shoals 2020 Stevens Creek 2025 Neal Shoals 2036 SCE&G is presently operating the Saluda hydroelectric project under an annual license (scheduled to expire in August) while its long-term re-licensing application is being reviewed by FERC.SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The licenses expire as follows:ProjectLicenseExpirationSaluda (Lake Murray)2012Fairfield Pumped Storage/Parr Shoals2020Stevens Creek2025Neal Shoals2036For a discussion of legislative and regulatory initiatives being implemented that will affect SCE&G’s transmission system, see Electric Operations within the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.SCE&G is subject to regulation by the NRC with respect to the ownership, construction, operation and decommissioning of its currently operating and planned nuclear generating facilities. The NRC’s jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants.RATE MATTERSFor a discussion of the impact of various rate matters, see the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G, and Note 2 to the consolidated financial statements for SCANA and SCE&G.Prior to the first billing cycle of January 2014, SCE&G's retail electric rates for its residential and certain small commercial customers included an eWNA approved by the SCPSC, which largely mitigated the impact of weather on electric margins. In connection with a December 2013 SCPSC order, SCE&G discontinued the eWNA.SCE&G’s retail electric rates include certain costs associated with its DSM Programs as authorized by the SCPSC. More specifically, these rates include the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs.Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%.In May 2011 and in November 2012, the SCPSC approved updated capital cost schedules sought by SCE&G that, among other matters, incorporated then-identifiable additional capital costs and revised substantial completion dates for the New Units, and included amounts to resolve certain claims. Details of these SCPSC approvals are further described in Notes 2 and 10 to the consolidated financial statements for SCANA and SCE&G.11In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates and authorized SCE&G an allowed return on common equity of 10.25% (related to non-BLRA expenditures). The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM Programs component rider to retail rates, among other things. See Note 2 to the consolidated financial statements for SCANA and SCE&G for additional details.SCE&G’s gas rate schedules for its residential, small commercial and small industrial customers include a WNA approved by the SCPSC, which is in effect for bills rendered for billing cycles in November through April. The WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues, but reduces fluctuations in revenues and earnings caused by abnormal weather.SCE&G’s retail electric rates include certain costs associated with the Company’s DSM Programs as authorized by the SCPSC. More specifically, these costs include the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers and it will continue on a pilot basis unless modified or terminated by the SCPSC.PSNC Energy is authorized by the NCUC to utilize a CUT which allows PSNC Energy to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors.Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflected the removal of the contingency reserve and incorporated then identifiable capital costs of $173.9 million (in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed in the OTHER MATTERS — Nuclear Generation section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 1 of the consolidated financial statements (e.g., those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site).The SCPSC’s fuel cost recovery procedure determines the fuel component in SCE&G’s retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any over-collection or under-collection from the preceding 12-month period. The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, mercury and particulates. SCE&G may request a formal proceeding concerning its fuel costs at any time should circumstances dictate such a review.&G’s retail electric rates are established in part using a&G's cost of fuel component approved byare described in Note 2 to the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased byconsolidated financial statements for SCANA and SCE&G. In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011. On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. The next annual hearing to review base rates for fuel costs is scheduled for March 22, 2012.SCE&G’s natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities.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. The annual PGA hearingSCPSC proceedings related to review SCE&G’s gas purchasing policies and procedures was conducted in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s&G's natural gas hedging program.PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs, andincluding gas costs that were uncollectible from certain uncollectible expenses related to gas cost.customers. The Rider D rate mechanism also allows it to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.In January 2012, NCUC proceedings related to PSNC Energy's rates are described in Note 2 to the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in February 2012.In December 2011, in connection with PSNC Energy’s 2011 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2011. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting that the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will have a material effect on the Company’s results of operations, cash flows, orconsolidated financial condition.In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2011.In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.ENVIRONMENTAL MATTERSFederal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be predicted. For a more complete discussion of how these regulations and standards impact SCANA and SCE&G, see the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 10 to the consolidated financial statements for SCANA and SCE&G.OTHER MATTERSFor a discussion of SCE&G’s insurance coverage for Summer Station Unit 1and1 and the New Units, see Note 10 to the consolidated financial statements for SCANA and SCE&G.12The risk factors that follow relate in each case to SCANA and its subsidiaries, and where indicated the risk factors also relate to SCE&G and its consolidated affiliates.Commodity price changes, delays and other factors may affect the operating cost, capital expenditures and competitive positions of the Company’s and Consolidated SCE&G’s energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.Our energy businesses are sensitive to changes in coal, natural gas, oiluranium and other commodity prices (as well as their transportation costs) and availability. Any such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. Consolidated SCE&G is permitted to recover the prudently incurred cost of 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 require the dispatch of gas-fired electric generation ahead of coal-fired electric generation, higher inventories of coal, with related increased carrying costs, may result. This may adversely affect our results of operations, cash flows and financial position.Gas cost increases alsoAccordingly, customers able to do so may result in lowerswitch to alternative forms of energy and reduce their usage by customersof gas from the Company and Consolidated SCE&G. Customers unable to switch to alternate fuels. Increases in fuel costsalternative fuels or suppliers may also result in higher prices for and thus lowerreduce their usage of electricity by customers.Certain construction-related commodities, such as copper and aluminum used in our transmission and distribution lines and in our electrical equipment, and steel, concrete and rare earth elements, have experienced significant price fluctuations due to changes in worldwide demand. To operate our air emissions control equipment, we use significant quantities of ammonia, limestone and lime. With EPA-mandated industry-wide compliance requirements for air emissions controls, 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 costs of large capital projects, such as the Company’s and Consolidated SCE&G’s construction for environmental compliance and its construction of the New Units and associated transmission, are significant and are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of the projects.The Company’s and Consolidated SCE&G’s businesses are capital intensive and require significant investments in energy generation and in other internal infrastructure projects, including projects for environmental compliance. For example, SCE&G and Santee Cooper have agreed to jointly own, contract the design constructand construction of, and operate the New Units, which will be two 1,117-megawatt1,250 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 towards project development, permitting, site preparation and long lead-time procurement. Substantial additional resources will be required for the construction and operation of the New Units upon receipt of requisite approvals.resources. In addition, planning and construction of significant new transmission resources areinfrastructure is necessary to support the New Units and areis under way as an integral part of the project. Achieving the intended benefits of any large construction project is subject to many uncertainties. For instance, the ability to stay withinadhere to established budgets and timeframes may be affected by many variables, such as the regulatory and legal processes associated with securing 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 unforeseen difficulties meeting critical regulatory requirements. There may be unforeseen engineering problems or unanticipated changes in project design or scope. Our ability to complete construction projects (including new baseload generation) as well as our ability to maintain current operations at reasonable cost could be affected by the availability of key components or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, new or enhanced environmental requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. 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 Matters in Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for SCANA and SCE&G.Should the construction of the New Units materially and adversely deviate from the schedules, estimates, and projections submitted to and approved by the SCPSC pursuant to the BLRA, the SCPSC could disallow the additional capital13costs 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. 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 New Units project.Furthermore, joint venturejointly owned projects, such as the current construction of the New Units, are subject to the risk that one or more of the joint venture partnersowners becomes either unable or unwilling to continue to fund project financial commitments, new partnersjoint owners cannot be secured at equivalent financial terms, or changes in the joint ventureownership 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 to manage and complete our capital projects, our results of operations, cash flows and financial condition may be adversely affected.The use of derivative instruments could result in financial losses and liquidity constraints. The Company and Consolidated SCE&G do not fully hedge against financial market risks or price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.The Company and Consolidated SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. The Company also uses such derivative instruments to manage certain commodity (i.e. natural gas) market risk. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and interest ratefinancial contracts or if a counterparty fails to perform under a contract.The Company strives to manage commodity price exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be diminished.recent federal legislation (Dodd-Frank)Dodd-Frank affects the use and reporting of derivative instruments. The regulations under this new legislation are still being finalizedprovide for substantial additional regulation of over-the-counter and their impact on the use ofsecurity-based derivative instruments, among other things, and require numerous rule-makings by the CFTC and the SEC to implement. 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, major swap participants and financial institutions, when possible, as well as entering into reporting party agreements with counterparties who also are not swap dealers, major swap participants or financial institutions, 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. Moreover, the Company retains reporting responsibility for certain types of swaps, such as the annual reporting of trade options. 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 determined at this time.Changing and complex laws and regulations to which the Company and Consolidated SCE&G are subject could adversely affect revenues, increase costs, or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.The Company and Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, IRS, EPA, CFTC and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by agencies of the state governments of South Carolina, North Carolina and Georgia includingvia regulatory agencies, state environmental commissions, and state employment commissions. Accordingly, the Company and Consolidated SCE&G must comply with extensive federal, state and local laws and regulations. Such governmental oversight and regulation broadly and materially affect the operation of our business. In addition to many other aspects of our business, these requirements impact the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our electric and natural gas transmission system,systems, the physical and cyber security of key assets, customer conservation through demand-side management programs,DSM Programs, information security, the issuance of securities and borrowing of money, financial reporting, interactioninteractions among affiliates, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual and wepotentially costly to effect compliance. We cannot predict the future course of14changes 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.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. In particular, Large capital projects, DSM Programs results 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. The Company’s interstate gas pipeline, SCE&G’s electric transmission system and Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the FERC, NRC and SCPSC. Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as market conditions evolve. Although we believe that we have constructive relationships with the regulators, our ability to obtain rate treatment that will allow us to maintain reasonable rates of return is dependent upon regulatory determinations, and there can be no assurance that we will be able to implement rate adjustments when sought.The Company and Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and which may impact our business plans or expose us to environmental liabilities.The Company and Consolidated SCE&G are subject to extensive federal, state and local environmental laws and regulations, including those relating to water quality and air emissions (such as reducing nitrogen oxide, sulfur dioxide, mercury and particulate matter). Some form of regulation may be forthcomingis expected at the federal and possibly state levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. On September 20, 2013, the EPA re-proposed NSPS for emissions of carbon dioxide from newly constructed fossil fuel-fired electric generating units. Standards, regulations, or guidelines are also expected for existing units by June 1, 2014, to be made final no later than June 1, 2015. A number of bills have been introduced in Congress that seek to require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted. On February 16, 2012, the EPA issued the finalized MATS for power plants that requires reduced emissions from new and existing coal and oil-fired electric utility steam generating facilities. The EPA has proposed requirements for cooling water intake structures to meet BACT, andthethe best technology available, and the EPA presently is drafting a final rule regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA has announced that it expects to overhaulproposed new standards under the Clean Water Act rulesCWA governing effluent limitation standardsguidelines for coal-fired power plants.Compliance with these environmental laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emissions fees and permitting at our facilities. These expenditures have been significant in the past and are expected to continue or even increase in the future. Changes in compliance requirements or more restrictive interpretations by governmental authorities of existing requirements may impose additional costs on us (such as the clean-up of MGP sites or additional emission allowances) or require us to incur additional capital expenditures or curtail some of our cost savings activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated renewable portfolio standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could negatively impact our industry, our business and our results of operations and financial position, especially if emissions or discharge limits are reduced or more onerous permitting requirements or additional regulatory requirements are imposed.15could result in lower usage of electricity by our customers. Although we cannot predict whether such standards will be adopted at the federal level or in South Carolina or their specifics if adopted, compliance with such potential portfolio standards could significantly impact our industry, our capital expenditures, and our results of operations and financial position.The 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 announced in 2012 that six of its oldest and smallest coal-fired units would be taken off-line or temporarily switched from coal to natural gas prior to closure in 2018. One of these units was retired in late 2012. Two other of these units were retired in late 2013.The Company and Consolidated SCE&G are vulnerable to interest rate increases, which would increase our borrowing costs, and may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.The Company and Consolidated SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company’s and Consolidated SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.The Company’s and 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 business. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.Disruptions in the capital markets and its actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial position, including its shareholders’ equity.A downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect our ability to access capital and to operate our businesses, thereby adversely affecting results of operations, cash flows and financial condition.Various rating agencies rate SCANA’s long-term senior unsecured debt, SCE&G’s long-term senior secured debt, and the long-term senior unsecured debt of PSNC Energy as investment grade. In addition, ratings agencies maintain ratings on the short-term debt of SCANA, SCE&G, Fuel Company (which ratings are based upon the guarantee of SCE&G) and PSNC Energy. If these rating agencies were to lower the outlook or downgrade any of these ratings, particularly to below investment grade, borrowing cost on new issuances would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease.OneIn 2011, one rating agency by action taken in 2011, downgraded both the short-term and senior unsecured long-term debt of SCANA. In 2013, another rating agency revised the outlook for SCANA and its subsidiaries to negative from stable. These downgrades and lowered outlook have increased SCANA’sthe short-term borrowing rate and decreased the average maturityrates of its short-term debt,SCANA and may have the effect of increasing SCANA’sthe long-term16borrowing rate.rates of SCANA and SCE&G. Although access to the short-term market has not been adversely impacted, this could change under different market conditions.SCANA’s leverage ratio of long- and short-term debt to capital was approximately 58%56% at December 31, 2011.2013. SCANA has publicly announced its desire to maintain its leverage ratio at levels between 54% and 57%, but SCANA’s ability to achieve and maintain those levelsdo so depends on a number of factors. In the future, if SCANA is not able to achieve and maintain its leverage ratio within the desired range, the Company’s debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its ability to access to the capital markets may be limited.Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.The Company has delivered less gas and received lower prices for natural gas in deregulated markets and consequently earned less income when weather conditions have been milder than normal.normal, and as a consequence earned less income from those operations. During 2010, the SCPSC approved SCE&G’s implementation of an eWNA on a pilot basis.basis; it was discontinued at the end of 2013. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and Consolidated SCE&G if the eWNA is not extended on&G. Hot or cold weather could result in higher bills for customers and result in higher write-offs of receivables and in a permanent basis.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 electromagnetic events and the 2011 earthquake and tsunami in Japan) or man-made mishaps (such as the San Bruno, California natural gas transmission pipeline failure, or the Kingston, Tennessee coal ash pond failure)failure, 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 indirectly impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial position, operating expenses, and cash flows.Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.The utility industry has been undergoing structural change for a number of years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales has been introducedvia a RTO/ISO (Regional Transmission Organization/Independent System Operator) is in effect across much of the country, but the Southeastern utilities have retained the traditional bundled, vertically integrated structure. Should a RTO/ISO-market be implemented in the Southeast, potential risks emerge from reliance on a national level. volatile wholesale market prices as well as increased costs associated with new delivery transmission and distribution infrastructure.Some states have also mandated or encouraged competition at theunbundled retail level. Increasedcompetition. Should this occur in South 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 would 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. As a result of federal and state subsidies and potential regulations allowing third-party retail sales, the growth of such distributed generation could be significant in the future. Such growth will lessen Company and Consolidated SCE&G sales and 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. Some economic sectors important to our customer base may be particularly affected. 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 costs17charged by suppliers, in changes into 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 or legislative or regulatory actions. Budget cutbacks also adversely affect funding levels of federal and state support agencies and non-profit organizations that assist low income customers with bill payments.In addition, conservation 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.Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.Critical processes or systems in the Company’s or Consolidated SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission line failure, information systems failure or security breach, the effects of drought (including reduced water levels) on the operation of emission control or other generation equipment, and the effects of a pandemic or terrorist attack on our workforce or facilities or on the ability of vendors and suppliers to maintain services key to our operations.In particular, as the operator of power generation facilities, many of which entered service prior to 1985 and may be difficult to maintain, Consolidated SCE&G could incur problems, such as the breakdown or failure of power generation or emission control equipment, transmission lines,equipment, or other equipment or processes which would result in performance below assumed levels of output or efficiency. The operation of the New Units 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. These purchases are subject to state regulatory prudency reviews for recovery through rates. Similarly, a gas transmission or distribution line failure of the Company or Consolidated SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers.Events such as these could entail substantial repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company’s revenues, results of operations, and financial condition.A failure of the Company 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 financial position, results of operations and cash flows.The Company depends on maintaining the physical and cyber security of its 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 business could have serious adverse impacts on the customers and communities that we serve. Virtually all of the Company's operations are dependent in some manner upon our cyber systems, which encompass electric and gas transmission and distribution 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, 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, employee, or corporate information. The Company 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 may18not be adequate to respond to these events. As a result, the Company's financial position, 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 SEMI, to pay dividends or to advance or repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.A significant portion of Consolidated SCE&G’s generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition. These risks will increase as the New Units are developed.In 2011,2013, Summer Station Unit 1, operated by SCE&G, provided approximately 55.6 million MWh, or 19%24% of our generation capacity. Ifgeneration. When the New Units are completed, our generating capacity and the percentage of total generating capacity represented by nuclear sources isare 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 contingencies if insurance coverage is inadequate; and·Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives.The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident, if a major incident should occur at a domestic nuclear facility, it could harm our results of operations, cash flows and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Finally, in today’s environment, there is a heightened risk of terrorist attack on the nation’s nuclear facilities, which has resulted in increased security costs at our nuclear plant.Failure to retain and attract key personnel could adversely affect the Company’s and Consolidated SCE&G’s operations and financial performance.ImplementationAs with many other utilities, a significant portion of our strategic plan and growth strategy requires that weworkforce 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 business. Competition for these employees is19high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance.The Company and Consolidated SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial position, and access to capital.From time to time, the Company and Consolidated SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plantplants and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved by regulators), to the detriment of the Company or Consolidated SCE&G. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or Consolidated SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial position, as well as limit our ability to access capital.The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure to adhere to high standards of compliance with laws and regulations, ethical conduct, operational effectiveness, and safety of employees, customers and the public. These risks could adversely affect the valuation of our common stock and the Company’s and Consolidated SCE&G’s access to capital.The Company and Consolidated SCE&G are committed to comply with all laws and regulations, to focus on the safety of employees, customers and the public, to maintain the privacy of information related to our customers and employees and to maintain effective communications with the public and key stakeholder groups, particularly during emergencies and times of crisis. The Company and Consolidated SCE&G also are committed to operational excellence and, through our Code of Conduct and Ethics, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments may subject the Company and Consolidated SCE&G not only to fraud, litigation and financial loss, but also to reputational risk that could adversely affect the valuation of SCANA’s stock, adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight. Insurance may not be available or adequate to respond to these events.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&G's bond indenture, securing the First Mortgage Bonds issued thereunder, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO’sGENCO's Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.For a brief description of the properties of SCANA’s other subsidiaries, which are not significant as defined in Rule 1-02 of Regulation S-X, see Item 1. BUSINESS—SEGMENTS OF BUSINESS—Nonregulated Businesses.ELECTRIC PROPERTIESThe following map indicates significant electric generation properties, which are further described below. Natural gas transmission and distribution properties, though not depicted on the map, are also described below.
ELECTRIC PROPERTIESSCE&G owns each oftable shows the electric generating facilities listed below unless otherwise noted.
Fuel Capability
In-Service
Capacity
(Summer Rating) (MW)(1)Represents SCE&G’s two-thirds portion of Summer Station Unit 1 (one-third owned by Santee Cooper).(2)The coal-fired steam unit at Williams Station is owned by GENCO.(3) Net Generating Capacity In-Service Summer Date (MW) Coal-Fired Steam: McMeekin - Near Irmo, SC 1958 250 * Wateree - Eastover, SC 1970 684 Williams - Goose Creek, SC 1973 605 Cope - Cope, SC 1996 415 Kapstone - Charleston, SC 1999 85 Gas-Fired Steam - Urquhart Unit 3 - Beech Island, SC 1953 95 * Nuclear - V. C. Summer - Parr, SC (reflects SCE&G's 66.7% ownership share) 1984 647 Internal Combustion Turbines: Peaking units - various locations in SC 1968-1999 352 Urquhart Combined Cycle - Beech Island, SC 2002 458 Jasper Combined Cycle - Jasper, SC 2004 852 Hydro: Saluda - Irmo, SC 1930 200 Other hydro units - various locations in or bordering SC 1905-1914 18 Fairfield Pumped Storage - Parr, SC 1978 576 * As described in Note 2 to the consolidated financial statements for SCANA and SCE&G, receives shaft horsepower from Kapstone Charleston Kraft, LLC, a biomass/coal cogeneration facility,under plans announced in 2012, SCE&G has retired or intends to operate SCE&G’s generator.(4)Two combined-cycle turbines burn natural gas or fuel oil to produce 330 MW of electric generation and use exhaust heat to power two 64 MW turbines at the Urquhart Generating Station. Unit 3 is a 95 MWretire six coal-fired steam unit.(5)SCE&G also owns three other hydro units in South Carolina that were placed in service in 1905 and 1914 and havewith an aggregate net generating capacity (summer rating) of 21 MW.SCE&G owns 16 combustion turbine peaking730 MW by 2018, subject to future developments in environmental regulations, among other matters. As of December 31, 2013, three of these units fueled by gas and/or oil located at various sites in SCE&G’s service territory. These turbines were placed in service at various times from 1961 to 2010 and havehad been retired (with an aggregate net generating capacity, summer rating, of 355 MW.SCE&G owns 441436 substations having an aggregate transformer capacity of 30 million KVA. The transmission system consists of 18,2953,307 miles of lines, and the distribution system consists of 6,76318,397 pole miles of overhead lines and 7,004 trench miles of underground lines.NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIESSCE&G’s&G's natural gas system includes 448 miles of transmission pipeline of up to 20 inches in diameter that connect its distribution system with Southern Natural, Transco and CGT. SCE&G’s distribution system consists of 16,54916,450 miles of distribution mains and related service facilities. SCE&G also owns two LNG plants, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF of natural gas. The Salley facility can store the liquefied equivalent of 900 MMCF of natural gas and has no liquefying capabilities. The LNG facilities have the capacity to regasify approximately 60 MMCF per day at Charleston and 90 MMCF per day at Salley.CGT’s natural gas system consists of 1,469 miles of transmission pipeline of up to 24 inches in diameter. CGT’s system transports gas to its customers from the transmission systems of Southern Natural at Port Wentworth, Georgia and Aiken County, South Carolina, Southern LNG, Inc. at Elba Island, near Savannah, Georgia and Transco in Cherokee and from Port Wentworth and Elba Island, Georgia.PSNC Energy’s natural gas system consists of 606594 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy’s distribution system consists of 10,20120,411 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF, the capacity to liquefy up to 4 MMCF per day and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly-owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition,ITEM 3. LEGAL PROCEEDINGSCertain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2011, are described below. These issues affect the Company and, to the extent indicated, also affect Consolidated SCE&G.In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with the CSAPR and the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide. This new standard may require some of SCE&G’s smaller coal-fired units to reduce their sulfur dioxide emissions to a level to be determined by EPA and/or DHEC. The costs incurred to comply with this new standard are expected to be recovered through rates.In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2014 and will cost an additional $8.3 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $3.1 million, the estimated remaining liability at December 31, 2011. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.LitigationIn May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. This settlement did not have a material impact on the Company’s results of operations, cash flows or financial condition.also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on their respective results of operations, cash flows or financial condition.The executive officers are elected at the annual meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such annual meeting, unless (1) a resignation is submitted, (2) the Board of Directors shall otherwise determine or (3) as provided in the By-laws of SCANA. Positions held are for SCANA and all subsidiaries unless otherwise indicated.NameAgeName Positions Held During Past Five Years 58 56Chairman of the Board and Chief Executive Officer and DirectorPresident and Chief Operating Officer -SCANAPresident and Chief Operating Officer-SCE&G2011-present2011-present*-201153 51Executive Vice PresidentChief Financial OfficerSenior Vice President2012-present*-present*-201256 54Senior Vice PresidentSenior Vice President and Chief Nuclear Officer-SCE&GSenior Vice President-SCANAVice President of Nuclear Plant Operations-SCE&G2009-present2010-present2009-present*-200965 63President and Chief Operating Officer-SEMI, SCI and ServiceCareSenior Vice President-SCANA*-present*-present56 54Senior Vice President-Fuel Procurement and Asset Management- SCEManagement-SCE&Gand PSNC EnergySenior Vice President-SCANA*-present*-present54 52President of Generation and Transmission and Chief Operating Officer-SCE&GExecutive Vice President-SCANAExecutive Vice President-Generation and Transmission-SCETransmission -SCE&GExecutive Vice President-Generation, Nuclear and Fossil Hydro-SCE&G2011-present2009-present20112009-2011Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G2011-present2009-present20112009-2011*-200960 58President and Chief Operating Officer-CGTSenior Vice President-SCANA*-present*-presentD. Russell Harris 49 President of Gas Operations-SCE&GPresident and Chief Operating Officer-PSNC EnergySenior Vice President-Transmission Services-SCE&GPresident-Gas Distribution-SCANASenior Vice President-SCANA2013-present*-present2008-present*-20072013-present2012-201347 45President of Retail Operations-SCE&GSenior Vice President-SCANASenior Vice President-Retail Electric-SCE&GVice President-Electric Operations-SCE&G2011-present2011-present2011*-201163 61Executive Vice President, General Counsel and Secretary of BowaterIncorporated, Greenville, South Carolina2009-present*-2008-present 69 67Senior Vice President-Governmental Affairs and EconomicDevelopment-SCANA Development-SCANA ServicesSenior Vice President-SCANA*-present*-present59 57Senior Vice President-Administration-SCANAVice President-Gas Operations-SCE&G2012-present*-2012* Indicates position held at least since March 1, 2007.262009.21
2011 2010 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. High $ 45.48 $ 41.58 $ 42.20 $ 42.83 $ 41.97 $ 40.82 $ 39.99 $ 38.17 Low $ 38.49 $ 34.64 $ 38.16 $ 37.86 $ 40.03 $ 35.23 $ 34.73 $ 34.23 ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIESCOMMON STOCK INFORMATIONSCANA Corporation:Price Range (New York Stock Exchange(NYSE Composite Listing): 2013 2012 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. High $ 48.15 $ 52.93 $ 54.41 $ 51.23 $ 49.64 $ 50.34 $ 48.24 $ 46.12 Low $ 44.75 $ 45.72 $ 47.22 $ 45.57 $ 44.71 $ 47.18 $ 43.32 $ 43.56 SCANA common stock trades on The New York Stock Exchange,the NYSE using the ticker symbol SCG. Newspaper stock listings use the name SCANA. At February 20, 20122014 there were 130,295,890141,144,841 shares of SCANA common stock outstanding which were held by approximately 29,13428,121 shareholders of record. For a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2011,2013, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.SCANA declared quarterly dividends on its common stock of $.485$.5075 per share in 20112013 and $.475$.495 per share in 2010.2012. On February 15, 2012,20, 2014, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.495$.525 per share, an increase of 2.1%approximately 3.5%. The newnext quarterly dividend is payable April 1, 20122014 to shareholders of record on March 9, 2012.10, 2014. For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources-Financing Limits and Related Matters and Note 3 to the consolidated financial statements for SCANA.SCE&G:All of SCE&G’s common stock is owned by SCANA, and no established public trading market exists for SCE&G common stock. During 20112013 and 2010,2012, SCE&G declared quarterly dividends on its common stock in the following amounts:Declaration DateAmountDeclaration DateAmountFebruary 11, 2010$45.0 millionFebruary 11, 2011$49.0 millionMay 6, 201046.0 millionApril 21, 201147.5 millionJuly 29, 201049.0 millionAugust 11, 201149.0 millionOctober 27, 201052.4 millionOctober 26, 201138.0 millionDeclaration Date Amount Declaration Date Amount February 15, 2012 $ 51.6 million February 20, 2013 $ 62.2 million May 3, 2012 52.3 million April 25, 2013 62.0 million August 2, 2012 54.0 million July 31, 2013 65.8 million October 24, 2012 44.3 million October 31, 2013 60.0 million On February 15, 2012,20, 2014, SCE&G declared dividends on its common stock of $51.6$62.5 million.For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources-Financing Limits and Related Matters and Note 3 to the consolidated financial statements for SCE&G.2722
ITEM 6. SELECTED FINANCIAL DATAAs of or for the Year Ended December 31, 2013 2012 2011 2010 2009 (Millions of dollars, except statistics and per share amounts) SCANA: Statement of Income Data Operating Revenues $ 4,495 $ 4,176 $ 4,409 $ 4,601 $ 4,237 Operating Income $ 910 $ 859 $ 813 $ 768 $ 699 Preferred Stock Dividends $ — $ — $ — $ — $ 9 Income Available to Common Shareholders $ 471 $ 420 $ 387 $ 376 $ 348 Common Stock Data Weighted Average Common Shares Outstanding (Millions) 138.7 131.1 128.8 125.7 122.1 Basic Earnings Per Share $ 3.40 $ 3.20 $ 3.01 $ 2.99 $ 2.85 Diluted Earnings Per Share $ 3.39 $ 3.15 $ 2.97 $ 2.98 $ 2.85 Dividends Declared Per Share of Common Stock $ 2.03 $ 1.98 $ 1.94 $ 1.90 $ 1.88 Balance Sheet Data Utility Plant, Net $ 11,643 $ 10,896 $ 10,047 $ 9,662 $ 9,009 Total Assets $ 15,164 $ 14,616 $ 13,534 $ 12,968 $ 12,094 Total Equity $ 4,664 $ 4,154 $ 3,889 $ 3,702 $ 3,408 Short-term and Long-term Debt $ 5,825 $ 5,744 $ 5,306 $ 4,909 $ 4,846 Other Statistics Electric: Customers (Year-End) 678,273 669,966 664,196 660,580 654,766 Total sales (Million kWh) 22,313 23,879 24,188 24,884 23,104 Generating capability-Net MW (Year-End) 5,237 5,533 5,642 5,645 5,611 Territorial peak demand-Net MW 4,574 4,761 4,885 4,735 4,557 Regulated Gas: Customers, excluding transportation (Year-End) 837,232 818,983 803,644 794,841 782,192 Sales, excluding transportation (Thousand Therms) 921,533 798,978 812,416 931,879 832,931 Transportation customers (Year-End) 496 499 492 491 482 Transportation volumes (Thousand Therms) 1,729,399 1,559,542 1,585,202 1,546,234 1,388,096 Retail Gas Marketing: Retail customers (Year-End) 454,104 449,144 455,258 464,123 455,198 Firm customer deliveries (Thousand Therms) 382,728 310,442 341,554 402,583 347,324 Nonregulated interruptible customer deliveries (Thousand Therms) 1,928,266 1,981,085 1,845,327 1,728,161 1,628,942 SCE&G: Statement of Income Data Operating Revenues $ 2,845 $ 2,809 $ 2,819 $ 2,815 $ 2,569 Operating Income $ 737 $ 717 $ 654 $ 604 $ 547 Net Income $ 391 $ 352 $ 316 $ 304 $ 288 Net Income Attributable to Noncontrolling Interest $ 11 $ 11 $ 10 $ 14 $ 7 Preferred Stock Dividends $ — $ — $ — $ — $ 9 Earnings Available to Common Shareholder $ 380 $ 341 $ 306 $ 290 $ 272 Balance Sheet Data Utility Plant, Net $ 10,048 $ 9,375 $ 8,588 $ 8,198 $ 7,595 Total Assets $ 12,700 $ 12,104 $ 11,037 $ 10,574 $ 9,813 Total Equity $ 4,489 $ 4,043 $ 3,773 $ 3,541 $ 3,259 Short-term and Long-term Debt $ 4,306 $ 4,171 $ 3,753 $ 3,440 $ 3,430 Other Statistics Electric: Customers (Year-End) 678,338 670,030 664,273 660,642 654,830 Total sales (Million kWh) 22,327 23,899 24,200 24,887 23,107 Generating capability-Net MW (Year-End) 5,237 5,533 5,642 5,645 5,611 Territorial peak demand-Net MW 4,574 4,761 4,885 4,735 4,557 Regulated Gas: Customers, excluding transportation (Year-End) 329,179 322,419 316,683 313,346 309,687 Sales, excluding transportation (Thousand Therms) 457,119 412,163 407,073 447,057 399,752 Transportation customers (Year-End) 173 166 155 148 130 Transportation volumes (Thousand Therms) 155,190 260,215 192,492 190,931 217,750 23
As of or for the Year Ended December 31, |
| 2011 |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
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| (Millions of dollars, except statistics and per share amounts) |
| |||||||||||||
SCANA: |
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Statement of Income Data |
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|
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|
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|
|
|
| |||||
Operating Revenues |
| $ | 4,409 |
| $ | 4,601 |
| $ | 4,237 |
| $ | 5,319 |
| $ | 4,621 |
|
Operating Income |
| $ | 813 |
| $ | 768 |
| $ | 699 |
| $ | 710 |
| $ | 633 |
|
Other Expense |
| $ | (258 | ) | $ | (233 | ) | $ | (175 | ) | $ | (176 | ) | $ | (153 | ) |
Preferred Stock Dividends |
| $ | — |
| $ | — |
| $ | (9 | ) | $ | (7 | ) | $ | (7 | ) |
Income Available to Common Shareholders |
| $ | 387 |
| $ | 376 |
| $ | 348 |
| $ | 346 |
| $ | 320 |
|
Common Stock Data |
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|
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|
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|
|
| |||||
Weighted Average Common Shares Outstanding (Millions) |
| 128.8 |
| 125.7 |
| 122.1 |
| 117.0 |
| 116.7 |
| |||||
Basic Earnings Per Share |
| $ | 3.01 |
| $ | 2.99 |
| $ | 2.85 |
| $ | 2.95 |
| $ | 2.74 |
|
Diluted Earnings Per Share |
| $ | 2.97 |
| $ | 2.98 |
| $ | 2.85 |
| $ | 2.95 |
| $ | 2.74 |
|
Dividends Declared Per Share of Common Stock |
| $ | 1.94 |
| $ | 1.90 |
| $ | 1.88 |
| $ | 1.84 |
| $ | 1.76 |
|
Balance Sheet Data |
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Utility Plant, Net |
| $ | 10,047 |
| $ | 9,662 |
| $ | 9,009 |
| $ | 8,305 |
| $ | 7,538 |
|
Total Assets |
| $ | 13,534 |
| $ | 12,968 |
| $ | 12,094 |
| $ | 11,502 |
| $ | 10,165 |
|
Total Equity |
| $ | 3,889 |
| $ | 3,702 |
| $ | 3,408 |
| $ | 3,045 |
| $ | 2,960 |
|
Short-term and Long-term Debt |
| $ | 5,306 |
| $ | 4,909 |
| $ | 4,846 |
| $ | 4,698 |
| $ | 3,852 |
|
Other Statistics |
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Electric: |
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Customers (Year-End) |
| 664,196 |
| 660,580 |
| 654,766 |
| 649,571 |
| 639,258 |
| |||||
Total sales (Million KWh) |
| 24,188 |
| 24,884 |
| 23,104 |
| 24,284 |
| 24,885 |
| |||||
Generating capability-Net MW (Year-End) |
| 5,642 |
| 5,645 |
| 5,611 |
| 5,695 |
| 5,749 |
| |||||
Territorial peak demand-Net MW |
| 4,885 |
| 4,735 |
| 4,557 |
| 4,789 |
| 4,926 |
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Regulated Gas: |
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Customers, excluding transportation (Year-End) |
| 803,644 |
| 794,841 |
| 782,192 |
| 774,502 |
| 759,336 |
| |||||
Sales, excluding transportation (Thousand Therms) |
| 812,416 |
| 931,879 |
| 832,931 |
| 848,568 |
| 823,976 |
| |||||
Transportation customers (Year-End) |
| 492 |
| 491 |
| 482 |
| 474 |
| 446 |
| |||||
Transportation volumes (Thousand Therms) |
| 1,585,202 |
| 1,546,234 |
| 1,388,096 |
| 1,366,675 |
| 1,369,684 |
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Retail Gas Marketing: |
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| |||||
Retail customers (Year-End) |
| 455,258 |
| 464,123 |
| 455,198 |
| 459,250 |
| 484,565 |
| |||||
Firm customer deliveries (Thousand Therms) |
| 341,554 |
| 402,583 |
| 347,324 |
| 356,288 |
| 340,743 |
| |||||
Nonregulated interruptible customer deliveries (Thousand Therms) |
| 1,845,327 |
| 1,728,161 |
| 1,628,942 |
| 1,526,933 |
| 1,548,878 |
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SCE&G: |
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Statement of Income Data |
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| |||||
Operating Revenues |
| $ | 2,819 |
| $ | 2,815 |
| $ | 2,569 |
| $ | 2,816 |
| $ | 2,481 |
|
Operating Income |
| $ | 654 |
| $ | 604 |
| $ | 547 |
| $ | 559 |
| $ | 498 |
|
Other Expense |
| $ | (198 | ) | $ | (170 | ) | $ | (119 | ) | $ | (122 | ) | $ | (117 | ) |
Preferred Stock Dividends |
| $ | — |
| $ | — |
| $ | (9 | ) | $ | (7 | ) | $ | (7 | ) |
Earnings Available to Common Shareholders |
| $ | 306 |
| $ | 290 |
| $ | 272 |
| $ | 273 |
| $ | 245 |
|
Balance Sheet Data |
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Utility Plant, Net |
| $ | 8,588 |
| $ | 8,198 |
| $ | 7,595 |
| $ | 6,905 |
| $ | 6,202 |
|
Total Assets |
| $ | 11,037 |
| $ | 10,574 |
| $ | 9,813 |
| $ | 9,052 |
| $ | 7,977 |
|
Total Equity |
| $ | 3,773 |
| $ | 3,541 |
| $ | 3,259 |
| $ | 2,799 |
| $ | 2,711 |
|
Short-term and Long-term Debt |
| $ | 3,753 |
| $ | 3,440 |
| $ | 3,430 |
| $ | 3,320 |
| $ | 2,593 |
|
Other Statistics |
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Electric: |
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| |||||
Customers (Year-End) |
| 664,273 |
| 660,642 |
| 654,830 |
| 649,636 |
| 639,312 |
| |||||
Total sales (Million KWh) |
| 24,200 |
| 24,887 |
| 23,107 |
| 24,287 |
| 24,888 |
| |||||
Generating capability-Net MW (Year-End) |
| 5,642 |
| 5,645 |
| 5,611 |
| 5,695 |
| 5,749 |
| |||||
Territorial peak demand-Net MW |
| 4,885 |
| 4,735 |
| 4,557 |
| 4,789 |
| 4,926 |
| |||||
Regulated Gas: |
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| |||||
Customers, excluding transportation (Year-End) |
| 316,683 |
| 313,346 |
| 309,687 |
| 307,074 |
| 302,469 |
| |||||
Sales, excluding transportation (Thousand Therms) |
| 407,073 |
| 447,057 |
| 399,752 |
| 416,075 |
| 407,204 |
| |||||
Transportation customers (Year-End) |
| 155 |
| 148 |
| 130 |
| 120 |
| 115 |
| |||||
Transportation volumes (Thousand Therms) |
| 192,492 |
| 190,931 |
| 217,750 |
| 64,034 |
| 27,113 |
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29
2011 2010 2009 % of Revenues Regulated 74 % 73 % 73 % Nonregulated 26 % 27 % 27 % % of Income Available to Common Shareholders Regulated 97 % 96 % 96 % Nonregulated 3 % 4 % 4 % % of Assets Regulated 94 % 95 % 94 % Nonregulated 6 % 5 % 6 %SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and sale of electricity in parts of South Carolina and in the purchase, transmission and sale of natural gas in portions of North Carolina and South Carolina. Through a wholly-owned nonregulated subsidiary, SCANA markets natural gas to retail customers in Georgia and to wholesale customers primarily in the southeast. Other wholly- ownedwholly-owned nonregulated subsidiaries provide fiber optic and other telecommunications services and provide service contracts to homeowners on certain home appliances and heating and air conditioning units. A service company subsidiary of SCANA provides administrative, management and other services to SCANA and its subsidiaries.The following map indicates areas where the Company’s significant business segments conduct their activities, as further described in this overview section.
The following percentages reflect revenues and net income available to common shareholders earned by the Company’s regulated and nonregulated businesses (including the holding company) and the percentage of total assets held by them.30 2013 2012 2011 Revenues Regulated 75 % 77 % 74 % Nonregulated 25 % 23 % 26 % Net Income Regulated 97 % 99 % 97 % Nonregulated 3 % 1 % 3 % Assets Regulated 95 % 95 % 94 % Nonregulated 5 % 5 % 6 % 25
Key Earnings Drivers and Outlook
Unemployment (seasonally adjusted) |
| United States |
| Georgia |
| North Carolina |
| South Carolina |
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December 31, 2011 (preliminary) |
| 8.5 | % | 9.7 | % | 9.9 | % | 9.5 | % |
December 31, 2010 |
| 9.4 | % | 10.4 | % | 9.8 | % | 10.9 | % |
civilian labor force participation rate was 62.8% at December 31, 2013, matching a 35-year low.
| Unemployment (seasonally adjusted) | United States | Georgia | North Carolina | South Carolina | |||
| December 31, 2013 (preliminary) | 6.7% | 7.4% | 6.9% | 6.6% | |||
| December 31, 2012 | 7.8% | 8.7% | 9.4% | 8.6% | |||
| December 31, 2011 | 8.9% | 9.4% | 10.4% | 9.6% | |||
SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units. Units are complete.
consolidated financial statements.
Federal Register on
informed the Consortium that it intendsIn response to pursue the alternative that would delay the substantial completion date of the first New Unit and accelerate the substantial completion datea federal court order to establish a definite timeline for the second New Unit and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.
In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactor to be used for the New Units. This certification is a necessary step before the NRC can issue a COL for the New Units. In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.
See additional discussion at OTHER MATTERS - Nuclear Generation.
Environmental
Significant federal legislative initiatives related to energy were unsuccessful in 2011, and the Company expects such legislative initiatives will be hampered through 2012, due to each chamber of Congress being controlled by different political parties. The EPA, however, did issue new rules in 2011 related to air quality, including CSAPR and MATS, which require reductions in
power plant emissions of sulfur dioxide, nitrogen oxide and mercury, among other substances. Though implementation of CSAPR was stayed by the United States Court of Appeals for the District of Columbia pending judicial review, the Company cannot predict the outcome that judicial review will have on the rule’s implementation. In 2012, additional significant regulatory initiatives byCCR rule, the EPA and other federal agencieshas said it will likely proceed. These initiatives may require the Company to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. The Company cannot predict whether such initiatives will be enacted, and if they are, the conditions they would impose on utilities.
The EPA has stated its intention to propose, in late 2012,issue new federal regulations affecting the management and disposal of CCR,CCRs, such as ash.ash, by December 14, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.
equity of 10.25% for SCE&G and 10.60% for PSNC Energy.
Retail Gas Marketing
In addition, SCANA Energy's operating results are highly sensitive to weather. This market has matured in the last decade, resulting in lower margins and enhanced competition for customers.
The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control growth of costs. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth. In addition, certain pipeline capacity available for Energy Marketing to serve industrial and other customers is dependent upon the market share held by SCANA Energy in the retail market.
|
| 2011 |
| 2010 |
| 2009 |
| |||
Basic earnings per share |
| $ | 3.01 |
| $ | 2.99 |
| $ | 2.85 |
|
Diluted earnings per share |
| $ | 2.97 |
| $ | 2.98 |
| $ | 2.85 |
|
Cash dividends declared (per share) |
| $ | 1.94 |
| $ | 1.90 |
| $ | 1.88 |
|
| 2013 | 2012 | 2011 | |||||||||
| Basic earnings per share | $ | 3.40 | $ | 3.20 | $ | 3.01 | |||||
| Diluted earnings per share | $ | 3.39 | $ | 3.15 | $ | 2.97 | |||||
| Cash dividends declared (per share) | $ | 2.03 | $ | 1.98 | $ | 1.94 | |||||
| ||
| ||
| 2013 vs | Basic earnings per share increased | |
| 2012 vs 2011 | Basic earnings per share increased due to higher electric and gas margins and gains on sales of | |
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Operating revenues | $ | 2,430.5 | (0.9 | )% | $ | 2,453.1 | 0.9 | % | $ | 2,432.2 | ||||||||
| Less: Fuel used in generation | 751.0 | (11.0 | )% | 844.2 | (8.5 | )% | 922.5 | |||||||||||
| Purchased power | 43.0 | 53.0 | % | 28.1 | 46.4 | % | 19.2 | |||||||||||
| Margin | $ | 1,636.5 | 3.5 | % | $ | 1,580.8 | 6.1 | % | $ | 1,490.5 | ||||||||
| 2013 vs 2012 | Margin increased primarily due to base rate increases under the BLRA of | |
| 2012 vs 2011 | Margin increased primarily by $54.4 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA, by $3.7 million due to customer growth and by $11.0 million due to the expiration of a decrement rider approved in the 2010 retail electric base rate case. | |
| Classification | 2013 | Change | 2012 | Change | 2011 | ||||||||||
| Residential | 7,571 | — | 7,571 | (8.0 | )% | 8,232 | |||||||||
| Commercial | 7,205 | (1.2 | )% | 7,291 | (1.4 | )% | 7,397 | ||||||||
| Industrial | 6,000 | 2.8 | % | 5,836 | (1.7 | )% | 5,938 | ||||||||
| Other | 581 | (0.9 | )% | 586 | 2.4 | % | 572 | ||||||||
| Total retail sales | 21,357 | 0.3 | % | 21,284 | (3.9 | )% | 22,139 | ||||||||
| Wholesale | 955 | (63.2 | )% | 2,595 | 26.6 | % | 2,049 | ||||||||
| Total Sales | 22,312 | (6.6 | )% | 23,879 | (1.3 | )% | 24,188 | ||||||||
| 2013 vs 2012 | Retail sales volume increased primarily due to customer growth and the effects of weather, partially offset by lower average use. The decrease in wholesale sales is primarily due to the expiration of two customer contracts. | |
| 2012 vs 2011 | Retail sales volume decreased by 983 GWh primarily due to the effects of milder weather. The increase in wholesale sales is primarily due to higher contract utilization by a wholesale customer. | |
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Operating revenues | $ | 942.6 | 23.2 | % | $ | 765.0 | (9.0 | )% | $ | 840.4 | ||||||||
| Less: Gas purchased for resale | 534.9 | 42.8 | % | 374.6 | (19.7 | )% | 466.3 | |||||||||||
| Margin | $ | 407.7 | 4.4 | % | $ | 390.4 | 4.4 | % | $ | 374.1 | ||||||||
| 2013 vs 2012 | Margin increased primarily due to the SCPSC-approved increase in base rates under the RSA which became effective with the first billing cycle of November 2012, as well as residential and commercial customer growth and increased industrial usage. | |
| 2012 vs 2011 | Margin at SCE&G increased by $8.3 million due to the SCPSC-approved increases in retail gas base rates under the RSA which became effective with the first billing cycles of November 2011 and 2012. Margin at PSNC Energy increased by $5.1 million primarily due to residential and commercial customer growth and increased industrial sales due to the competitive price of gas versus alternate fuel sources. | |
| Classification (in thousands) | 2013 | Change | 2012 | Change | 2011 | ||||||||||
| Residential | 41,268 | 24.4 | % | 33,161 | (9.3 | )% | 36,568 | ||||||||
| Commercial | 28,181 | 12.7 | % | 25,001 | (3.0 | )% | 25,772 | ||||||||
| Industrial | 22,319 | 4.6 | % | 21,340 | 13.6 | % | 18,782 | ||||||||
| Transportation gas | 42,221 | 9.0 | % | 38,736 | 13.4 | % | 34,152 | ||||||||
| Total | 133,989 | 13.3 | % | 118,238 | 2.6 | % | 115,274 | ||||||||
| 2013 vs 2012 | Total sales volumes increased primarily due to customer growth, increased industrial usage and the effects of weather. | |
| 2012 vs 2011 | Residential and commercial sales volume decreased primarily due to milder weather. Industrial and transportation sales volumes increased due to the competitive price of gas versus alternate fuel sources. | |
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Operating revenues | $ | 465.2 | 12.8 | % | $ | 412.5 | (13.8 | )% | $ | 478.8 | ||||||||
| Net Income | 23.8 | * | 10.5 | (56.6 | )% | 24.2 | ||||||||||||
| 2013 vs 2012 | Changes in operating revenues and net income are due to higher demand in 2013 primarily as a result of milder weather in 2012. | |
| 2012 vs 2011 | Reductions in operating revenues and net income were primarily due to milder weather and a decrease in the number of customers served under the regulated provider program in 2012. | |
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Operating revenues | $ | 818.5 | 22.3 | % | $ | 669.0 | (20.8 | )% | $ | 844.9 | ||||||||
| Net Income | 6.1 | 13.0 | % | 5.4 | 22.7 | % | 4.4 | |||||||||||
| 2013 vs 2012 | Operating revenues and net income increased due to higher industrial sales volume and higher market prices. | |
| 2012 vs 2011 | Operating revenues decreased due to lower market prices. Net income increased due to higher consumption. | |
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Other operation and maintenance | $ | 707.5 | 2.6 | % | $ | 689.3 | 4.8 | % | $ | 657.9 | ||||||||
| Depreciation and amortization | 378.1 | 6.2 | % | 356.1 | 2.8 | % | 346.3 | |||||||||||
| Other taxes | 219.7 | 6.1 | % | 207.1 | 3.1 | % | 200.8 | |||||||||||
| 2013 vs 2012 | Other operation and maintenance expenses increased by $16.7 million due to incremental expenses associated with the December 2012 SCPSC rate order and by $5.7 million due to higher electric generation, transmission and distribution expenses. These increases were partially offset by lower | ||
|
|
| |
Diluted Earnings Per Share
In May 2010, SCANA entered into equity forward contracts for approximately 6.6 million common shares. During periods when the average market price of SCANA’s common stock is above the per share adjusted forward sales price, the
Company computes diluted earnings per share giving effect to this dilutive potential common stock utilizing the treasury stock method.
Pension Cost
Pension Net periodic benefit cost was recorded on the Company’sCompany's income statements and balance sheets as follows:
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| |||
Income Statement Impact: |
|
|
|
|
|
|
| |||
Increase in employee benefit costs |
| $ | 2.6 |
| $ | 1.1 |
| — |
| |
Other expense (income) |
| 0.5 |
| (3.9 | ) | $ | (3.7 | ) | ||
Balance Sheet Impact: |
|
|
|
|
|
|
| |||
Increase in capital expenditures |
| 3.9 |
| 6.0 |
| 9.8 |
| |||
Component of amount receivable from Summer Station co-owner |
| 1.2 |
| 1.7 |
| 2.7 |
| |||
Increase in regulatory asset |
| 9.1 |
| 18.6 |
| 31.2 |
| |||
Total Pension Cost |
| $ | 17.3 |
| $ | 23.5 |
| $ | 40.0 |
|
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Income Statement Impact: | ||||||||||||||||||
| Employee benefit costs | $ | 15.5 | * | $ | 4.0 | 53.8 | % | $ | 2.6 | |||||||||
| Other expense | 1.0 | 25.0 | % | 0.8 | 60.0 | % | 0.5 | |||||||||||
| Balance Sheet Impact: | ||||||||||||||||||
| Increase in capital expenditures | 7.2 | 9.1 | % | 6.6 | 69.2 | % | 3.9 | |||||||||||
| Component of amount receivable from Summer Station co-owner | 2.5 | 13.6 | % | 2.2 | 83.3 | % | 1.2 | |||||||||||
| Increase in regulatory asset | 5.5 | (63.1 | )% | 14.9 | 63.7 | % | 9.1 | |||||||||||
| Net periodic benefit cost | $ | 31.7 | 11.2 | % | $ | 28.5 | 64.7 | % | $ | 17.3 | ||||||||
No contributionbeing amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to gas operations through cost of service rates (see Note 2 to the pension trust was necessary, nor did limitations on benefit payments apply, in orconsolidated financial statements). In 2013, such amortizations totaled approximately $2.0 million for any period reported.
electric operations and $0.2 million for gas operations.
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Other income | $ | 100.3 | 71.2 | % | $ | 58.6 | 12.3 | % | $ | 52.2 | ||||||||
| Other expense | (45.5 | ) | 8.1 | % | (42.1 | ) | 5.3 | % | (40.0 | ) | ||||||||
| Total | $ | 54.8 | * | $ | 16.5 | 35.2 | % | $ | 12.2 | |||||||||
| 2013 vs 2012 | Changes in other income were primarily due to the recognition, pursuant to SCPSC accounting orders, of $50.1 million of gains realized upon the 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 regulatory liabilities. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income. This increase in other income was partially offset by the sales of communications towers that were recorded in 2012 by a non-regulated subsidiary. Changes in other expense were not significant. | |
| 2012 vs 2011 | Changes in other income were primarily due to the sales of communications towers in 2012 by a non-regulated subsidiary. Changes in other expense were not significant. | |
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Operating revenues |
| $ | 2,432.2 |
| 2.5 | % | $ | 2,373.9 |
| 10.5 | % | $ | 2,148.9 |
|
Less: Fuel used in generation |
| 922.5 |
| (2.6 | )% | 946.7 |
| 15.1 | % | 822.3 |
| |||
Purchased power |
| 19.2 |
| 12.9 | % | 17.0 |
| 1.2 | % | 16.8 |
| |||
Margin |
| $ | 1,490.5 |
| 5.7 | % | $ | 1,410.2 |
| 7.7 | % | $ | 1,309.8 |
|
|
|
|
|
|
|
Sales volumes (in GWh) related to the electric margin above, by class, were as follows:
Classification |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
|
Residential |
| 8,232 |
| (6.4 | )% | 8,791 |
| 11.4 | % | 7,893 |
|
Commercial |
| 7,397 |
| (3.7 | )% | 7,684 |
| 4.5 | % | 7,350 |
|
Industrial |
| 5,938 |
| 1.3 | % | 5,863 |
| 10.1 | % | 5,324 |
|
Other |
| 572 |
| (1.5 | )% | 581 |
| 3.4 | % | 562 |
|
Total retail sales |
| 22,139 |
| (3.4 | )% | 22,919 |
| 8.5 | % | 21,129 |
|
Wholesale |
| 2,049 |
| 4.3 | % | 1,965 |
| (0.5 | )% | 1,975 |
|
Total Sales |
| 24,188 |
| (2.8 | )% | 24,884 |
| 7.7 | % | 23,104 |
|
|
|
| |
|
|
|
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy. Gas Distribution sales margin (including transactions with affiliates) was as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Operating revenues |
| $ | 840.4 |
| (14.2 | )% | $ | 979.4 |
| 3.3 | % | $ | 948.4 |
|
Less: Gas purchased for resale |
| 466.3 |
| (22.5 | )% | 601.7 |
| 2.8 | % | 585.1 |
| |||
Margin |
| $ | 374.1 |
| (1.0 | )% | $ | 377.7 |
| 4.0 | % | $ | 363.3 |
|
|
|
| ||
|
|
|
Sales volumes (in DT) by class, including transportation gas, were as follows:
Classification (in thousands) |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
|
Residential |
| 36,568 |
| (19.2 | )% | 45,251 |
| 16.0 | % | 38,995 |
|
Commercial |
| 25,772 |
| (11.0 | )% | 28,972 |
| 6.4 | % | 27,220 |
|
Industrial |
| 18,782 |
| (0.4 | )% | 18,860 |
| 12.3 | % | 16,798 |
|
Transportation gas |
| 34,152 |
| 3.2 | % | 33,089 |
| 7.3 | % | 30,845 |
|
Total |
| 115,274 |
| (8.6 | )% | 126,172 |
| 10.8 | % | 113,858 |
|
|
|
| ||
|
|
|
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy which operates in Georgia’s natural gas market. Retail Gas Marketing revenues and income available to common shareholders were as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Operating revenues |
| $ | 478.8 |
| (13.4 | )% | $ | 552.9 |
| 6.0 | % | $ | 521.7 |
|
Income available to common shareholders |
| $ | 24.2 |
| (20.7 | )% | $ | 30.5 |
| 27.1 | % | $ | 24.0 |
|
|
|
| ||
|
|
|
Energy Marketing
Energy Marketing is comprised of the Company’s nonregulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and income available to common shareholders were as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Operating revenues |
| $ | 844.9 |
| (3.3 | )% | $ | 874.1 |
| 12.5 | % | $ | 776.9 |
|
Income available to common shareholders |
| $ | 4.4 |
| 12.8 | % | $ | 3.9 |
| 14.7 | % | $ | 3.4 |
|
|
|
| ||
|
|
|
Other Operating Expenses
Other operating expenses were as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Other operation and maintenance |
| $ | 657.9 |
| (1.8 | )% | $ | 669.9 |
| 4.7 | % | $ | 639.7 |
|
Depreciation and amortization |
| 346.3 |
| 3.3 | % | 335.1 |
| 6.0 | % | 316.0 |
| |||
Other taxes |
| 200.8 |
| 5.5 | % | 190.4 |
| 7.6 | % | 176.9 |
| |||
|
|
| |
|
|
|
Other Income (Expense)
Other income (expense) includes the results of certain incidental (non-utility) activities and the activities of certain non-regulated subsidiaries. Components of other income (expense) were as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Other income |
| $ | 52.2 |
| (0.9 | )% | $ | 52.7 |
| (21.0 | )% | $ | 66.7 |
|
Other expense |
| (40.0 | ) | 1.3 | % | (39.5 | ) | 7.0 | % | (36.9 | ) | |||
Total |
| $ | 12.2 |
| (7.6 | )% | $ | 13.2 |
| (55.7 | )% | $ | 29.8 |
|
|
|
| |
|
|
|
Interest Expense
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Interest on long-term debt, net |
| $ | 276.6 |
| 5.9 | % | $ | 261.1 |
| 14.3 | % | $ | 228.5 |
|
Other interest expense |
| 7.7 |
| 71.1 | % | 4.5 |
| (10.0 | )% | 5.0 |
| |||
Total |
| $ | 284.3 |
| 7.0 | % | $ | 265.6 |
| 13.7 | % | $ | 233.5 |
|
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Interest on long-term debt, net | $ | 292.8 | 0.9 | % | $ | 290.2 | 4.9 | % | $ | 276.6 | ||||||||
| Other interest expense | 4.6 | (11.5 | )% | 5.2 | (32.5 | )% | 7.7 | |||||||||||
| Total | $ | 297.4 | 0.7 | % | $ | 295.4 | 3.9 | % | $ | 284.3 | ||||||||
Income Taxes
Income tax expense (and the effective tax rate) increased in 2011 over 2010 primarilyyear and also decreased due to the accelerated amortizationreversal in 2012 of deferred EIZ Creditsinterest which had been accrued in 2011 related to offset undercollected fuel costs in 2010 pursuant to an SCPSC order and an increase in operating income. Incomea tax expense (and the effective tax rate) decreased in 2010 over 2009 primarily due to the above-mentioned accelerated amortization of EIZ Credits to offset undercollected fuel costs and the accelerated amortization of EIZ Credits in connection with the July 2010 retail electric rate order. (Seeuncertainty that was resolved (see Note 5 to the consolidated financial statements for reconciling differences between incomestatements).
37rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.
3.22.
net proceeds of approximately $196 million.
2014.
Millions of dollars |
| 2012 |
| 2013 |
| 2014 |
| |||
SCE&G - Normal |
|
|
|
|
|
|
| |||
Generation |
| $ | 143 |
| $ | 96 |
| $ | 79 |
|
Transmission & Distribution |
| 197 |
| 217 |
| 190 |
| |||
Other |
| 26 |
| 14 |
| 21 |
| |||
Gas |
| 49 |
| 51 |
| 57 |
| |||
Common |
| 14 |
| 18 |
| 13 |
| |||
Total SCE&G - Normal |
| 429 |
| 396 |
| 360 |
| |||
PSNC Energy |
| 57 |
| 65 |
| 70 |
| |||
Other |
| 54 |
| 41 |
| 32 |
| |||
Total Normal |
| 540 |
| 502 |
| 462 |
| |||
New Nuclear |
| 954 |
| 952 |
| 727 |
| |||
Cash Requirements for Construction |
| 1,494 |
| 1,454 |
| 1,189 |
| |||
Nuclear Fuel |
| 44 |
| 110 |
| 55 |
| |||
Total Estimated Capital Expenditures |
| $ | 1,538 |
| $ | 1,564 |
| $ | 1,244 |
|
| Millions of dollars | 2014 | 2015 | 2016 | |||||||||
| SCE&G - Normal | ||||||||||||
| Generation | $ | 136 | $ | 145 | $ | 112 | ||||||
| Transmission & Distribution | 230 | 280 | 258 | |||||||||
| Other | 14 | 25 | 19 | |||||||||
| Gas | 50 | 51 | 73 | |||||||||
| Common | 9 | 7 | 10 | |||||||||
| Total SCE&G - Normal | 439 | 508 | 472 | |||||||||
| PSNC Energy | 128 | 111 | 87 | |||||||||
| Other | 79 | 58 | 42 | |||||||||
| Total Normal | 646 | 677 | 601 | |||||||||
| New Nuclear (including transmission) | 950 | 905 | 667 | |||||||||
| Cash Requirements for Construction | 1,596 | 1,582 | 1,268 | |||||||||
| Nuclear Fuel | 67 | 30 | 147 | |||||||||
| Total Estimated Capital Expenditures | $ | 1,663 | $ | 1,612 | $ | 1,415 | ||||||
The Company’s contractual cash obligations as of December 31, 20112013 are summarized as follows:
|
| Payments due by periods |
| |||||||||||||
Millions of dollars |
| Total |
| Less than |
| 1 - 3 years |
| 4 - 5 years |
| More than |
| |||||
Long- and short-term debt, including interest |
| $ | 10,477 |
| $ | 1,216 |
| $ | 1,031 |
| $ | 547 |
| $ | 7,683 |
|
Capital leases |
| 13 |
| 4 |
| 6 |
| 3 |
| — |
| |||||
Operating leases |
| 56 |
| 11 |
| 16 |
| 1 |
| 28 |
| |||||
Purchase obligations |
| 4,367 |
| 984 |
| 2,307 |
| 412 |
| 664 |
| |||||
Other commercial commitments |
| 4,724 |
| 1,062 |
| 1,587 |
| 912 |
| 1,163 |
| |||||
Total |
| $ | 19,637 |
| $ | 3,277 |
| $ | 4,947 |
| $ | 1,875 |
| $ | 9,538 |
|
| 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 | $ | 10,954 | $ | 713 | $ | 885 | $ | 1,243 | $ | 8,113 | ||||||||||
| Capital leases | 17 | 3 | 10 | 2 | 2 | |||||||||||||||
| Operating leases | 41 | 7 | 12 | 3 | 19 | |||||||||||||||
| Purchase obligations | 3,938 | 2,067 | 1,648 | 221 | 2 | |||||||||||||||
| Other commercial commitments | 4,397 | 886 | 1,700 | 998 | 813 | |||||||||||||||
| Total | $ | 19,347 | $ | 3,676 | $ | 4,255 | $ | 2,467 | $ | 8,949 | ||||||||||
Future Value |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| After 2016 |
| ||||||
Total Project Cash Outlay |
| $ | 804 |
| $ | 825 |
| $ | 558 |
| $ | 575 |
| $ | 367 |
| $ | 232 |
|
estimated $500 million SCE&G expects it will cost to acquire an additional 5% ownership in the New Units as further described in New Nuclear Construction Matters.
SCE&G and GENCO havehas obtained FERC authority to issue short-term indebtedness (pursuantand to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes, or commercial paper 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.
2014.
At December 31, 2011 and 2010, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
|
| SCANA |
| SCE&G |
| PSNC Energy |
| ||||||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||||
Lines of Credit: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Committed long-term |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total |
| $ | 300 |
| $ | 300 |
| $ | 1,100 |
| $ | 1,100 |
| $ | 100 |
| $ | 100 |
|
LOC advances |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Weighted average interest rate |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Outstanding commercial paper (270 or fewer days) |
| $ | 131 |
| $ | 39 |
| $ | 512 |
| $ | 381 |
| $ | 10 |
| $ | — |
|
Weighted average interest rate |
| .63 | % | .35 | % | .56 | % | .42 | % | .57 | % | — |
| ||||||
Letters of credit supported by LOC |
| $ | 3 |
| $ | 3 |
| $ | .3 |
| $ | .3 |
| — |
| $ | — |
| |
Available |
| $ | 166 |
| $ | 258 |
| $ | 588 |
| $ | 719 |
| $ | 90 |
| $ | 100 |
|
consolidated financial statements.
With respect to hydroelectric projects, theThe Federal Power Act requires the appropriation of a portion of certain earnings therefrom.from hydroelectric projects. At December 31, 2011,2013, approximately $58.8$63.1 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.
SCANA may redeem the Hybrids on or after January 30, 2015, without payment of a make-whole amount.
5.28.
In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.
In October 2011, SCE&G issued $30 million of 3.22% first mortgage bonds due October 18, 2021. Proceeds from the sale of these bonds were used to redeem prior to maturity $30 million of the 5.7% pollution control facilities revenue bonds due November 1, 2024 issued by Orangeburg County, South Carolina, on SCE&G’s behalf.
In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds due February 1, 2041, which constituted a reopening of the prior offering of $250 million of 5.45% first mortgage bonds issued in January 2011. Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance other capital expenditures and for general corporate purposes.
In May 2011 SCANA issued $300 million of 4.75% medium term notes due May 15, 2021. Proceeds from the sale of these notes were used by SCANA to retire $300 million of its 6.875% medium term notes.
In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire PSNC Energy’s $150 million medium term notes due February 15, 2011.
SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010 and entered into forward agreements for the sale of approximately 6.6 million shares. The forward agreements, after being extended by amendment dated October 26, 2011, are to be settled no later than December 31, 2012.
In March 2010, PSNC Energy issued $100 million of 6.54% unsecured notes due March 30, 2020. Proceeds from the sale were used to pay down short-term debt and for general corporate purposes.
During 2011 the Company experienced net cash inflows related to financing activities of approximately $240 million primarily due to issuances of common stock and short-term and long-term debt, partially offset by repayment of long-term debt and payment of dividends.
The Company paid approximately $61$6 million, in 2011net, through the third quarter of 2013 to settle interest rate derivative contracts associated withupon the issuance of long-term debt for contracts that had been designated as hedges.
Pursuant to SCPSC accounting orders, $50.1 million of such gains were recognized within other income, with such gain recognition being fully offset by downward adjustments to revenues reflected within electric margin.
The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation for property placed in service in 2013. These incentives, along with certain other deductions, have had a positive impact on the cash flows of the Company.
Air Quality
These actions are expected to address many of the rules and regulations discussed herein.
In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the new source performance standards of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.
To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether the Company will be affected by the initiative in the future. The Company believes that any enforcement action relative to its compliance with the CAA would be without merit. The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with NSR.
Water Quality
The
Electric Operations
SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.
expense as incurred.
| Company | Regulatory Jurisdiction/Matters |
| SCANA | The SEC as to the issuance of certain securities and other matters and the FERC as to certain acquisitions and other matters. |
| SCANA and all subsidiaries | The CFTC to the extent they transact swaps as defined in Dodd-Frank. |
| SCE&G | The SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; the FERC as to issuance of short-term borrowings, guarantees of short-term indebtedness, certain acquisitions and other matters; and the NRC with respect to the ownership, construction, operation and decommissioning of its currently operated and planned nuclear generating facilities. NRC jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants. |
| SCE&G and GENCO | The FERC and DOE, under the Federal Power Act, as to the transmission of electric energy in interstate commerce, the sale of electric energy at wholesale for resale, the licensing of hydroelectric projects and certain other matters, including accounting. |
| GENCO | The SCPSC as to the issuance of securities (other than short-term borrowings) and the FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters. |
| Fuel Company | The SEC as to the issuance of certain securities. |
| PSNC Energy | The NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters, and the SEC as to the issuance of certain securities. |
| SCE&G, PSNC Energy and CGT | The PHMSA and the DOT as to integrity management requirements for gas distribution pipeline systems and natural gas transmission systems, respectively. |
| CGT | The FERC as to transportation rates, service, accounting and other matters. |
| SCANA Energy | The GPSC through its certification as a natural gas marketer in Georgia and specifically as to retail prices for customers served under its regulated provider contract. |
SCANA is subject to In addition, the jurisdiction of the SEC as to the issuance of certain securities and other matters and is subject to the jurisdiction of the FERC as to certain acquisitions and other matters.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.
GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.
SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting.
NaturalRSA allows natural gas distribution companies mayin South Carolina to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.
45
Effective February 12, 2010, the PHMSA issued a final rule establishing integrity management requirements for gas distribution pipeline systems. SCE&G has developed a plan and procedures to ensure that it will be fully compliant with this rule. SCE&G believes that any additional costs incurred to comply with the rule will be recoverable through rates.
Public Service Company of North Carolina, Incorporated
PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.
The Pipeline Safety Act directed the DOT to establish the Integrity Management Rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy’s approximately 617 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 63 miles are located within these areas. Through December 2011, PSNC Energy has assessed 99 percent of the pipeline and is required to complete its assessment of the remainder by December 2012. PSNC Energy will be required to reinspect these same miles of pipeline approximately every seven years. PSNC Energy currently estimates the total costs through December 2012 to be $7.5 million for the initial assessments, not including any subsequent remediation that may be required. Costs totaling $2.2 million were recovered through rates over a three-year period beginning November 1, 2008. The NCUC has authorized continuation of deferral accounting for certain costs incurred to comply with DOT’s pipeline integrity management requirements until resolution of PSNC Energy’s next general rate proceeding. As a result, PSNC Energy incurred an additional $3.5 million in costs between November 2008 and December 2011.
Carolina Gas Transmission Corporation
CGT has approximately 72 miles of transmission line that are covered by the Integrity Management Rule of the Pipeline Safety Act. CGT currently estimates the total cost to be $10.5 million for the initial assessments and any subsequent remediation required through December 2012.
the effects of different rate schedules changes in weather and, where applicable, the impact of weather normalization or other regulatory provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. Accounts receivable included unbilled revenues of $169.1$183.1 million at December 31, 20112013 and $221.1$189.8 million at December 31, 2010,2012, compared to total revenues of $4.4$4.5 billion and $4.6$4.2 billion for the years 20112013 and 2010,2012, respectively.
Accounting for Pensions and Other Postretirement Benefits
The Company recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. The Company’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $17.3 million recorded in 2011 reflects the use of a 5.56% discount rate, derived using a cash flow matching technique, and an assumed 8.25% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension cost amount was, reasonable. For purposes of comparison, using a discount rate of 5.31% in 2011 would have increased the Company’s pension cost by $1.3 million. Had the assumed long-term rate of return on assets been 8.00%, the Company’s pension cost for 2011 would have increased by $1.9 million.
The following information with respect to pension assets (and returns thereon) should also be noted.
The Company determines the fair value of a majority of its pension assets utilizing market quotes or derives them from modeling techniques that incorporate market data. Only a small portion of assets are valued using less transparent (so-called “Level 3”) methods.
In developing the expected long-term rate of return assumptions, the Company evaluates historical performance, targeted allocation amounts and expected payment terms. As of the beginning of 2011, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 4.2%, 8.1%, 9.8% and 10.2%, respectively. The 2011 expected long-term rate of return of 8.25% was based on a target asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. As of the beginning of 2012, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 4.2%, 6.8%, 8.6% and 9.3%, respectively. For 2012, the expected rate of return is 8.25%.
Due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, the Company recorded significant amounts of pension cost in 2009, 2010 and 2011 compared to the pension income recorded previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of this pension cost by deferring as a regulatory asset the amount of pension expense above the level that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010,
upon the new retail electric base rates becoming effective, SCE&G began deferring as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.
The pension trust is adequately funded under current regulations, and no contributions have been required since 1997. Management does not anticipate the need to make significant pension contributions until after 2012.
The Company accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 5.72%, derived using a cash flow matching technique, and recorded a net cost of $18.6 million for 2011. Had the selected discount rate been 5.47% (25 basis points lower than the discount rate referenced above), the expense for 2011 would have been $0.5 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.
Asset Retirement Obligations
Nuclear Generation
SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units.Units are complete.
As In addition, under the terms of the agreement previously reported,described, SCE&G has been advised byagreed to pay an amount equal to Santee Cooper that it is reviewing certain aspectsCooper's actual cost of its capital improvement program and long-term power supply plan, including the levelpercentage conveyed as of its participation inthe date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. This transaction will not affect the payment obligations between the parties during construction for the New Units. Santee Cooper has entered into a letterUnits, nor is it anticipated that the payments would be reflected in revised rates filings under the BLRA.
The Consortium has recently performed an impact study, at SCE&G’s request, related to various costfabrication and timing alternatives arising from the delay in the issuance datedelivery of sub-modules are a focus area of the COL from mid-2011,Consortium, including sub-modules for module CA20, which wasis part of the date assumed whenauxiliary building, and CA01, which houses components inside the EPC Contract was signed in 2008,containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its fabrication is underway. CA20 is expected to be ready for placement on the early-2012 issuance date currently anticipated by SCE&G. The impact study analyzed three scenarios, including (1) compressing the construction schedule for the first New Unit but retaining the original substantial completion dates set forth in the EPC Contract, (2) extending the substantial completion date for the first New Unit to accommodate the COL delay, or (3) delaying the substantial completion datenuclear island of the first New Unit and acceleratingin the
Table first quarter of Contents
2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of the first New Unit during the third quarter of 2014. With this schedule, the Consortium continues to indicate that the substantial completion date forof the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's 55% share of the New Units is approximately $200 million. SCE&G has recently informednot accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium that it intendsregarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the New Units, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.
such impacts could be material.
On February 29, 2012, SCE&G filed
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.
In March 2011 aearthquake-generated tsunami, resulting from a massive earthquakewhich severely damaged several nuclear generating units and their back-up cooling systems in Japan. TheSCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the disaster is being evaluated world-wide,construction and numerous politicaloperation of the New Units, and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at existing nuclear facilities, as well as those planned for construction. In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G, is evaluating.pursuant to the license condition, prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, noror how such initiatives would impact SCE&G’s&G's existing Summer Station or the licensing, construction or operation of the New Units.
In December 2011,
Fuel Contract
On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 andproduced by the New Units through 2033.(advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the New Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), SCE&G is dependent upon Westinghousehas applied to the IRS for providing fuel assembliesits allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification. Under current provisions of the new AP1000 passive reactorsInternal Revenue Code and based on SCE&G's current 55% ownership and other assumptions regarding volumes of electricity to be generated by the New Units, the aggregate production tax credits for which SCE&G qualifies could exceed $1.3 billion over the eight year period following each of the New Units' in-service dates. In January 2014, SCE&G amended its application to include the additional 5% interest in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering supportthat it expects to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support servicesacquire. Additional production tax credits related to the New Units upon their completion and commencement of commercial operation.
5% interest could total as much as $125 million.
In July 2010,
Futures Trading CommissionCFTC and the SEC to implement. The Company has determined that it meets the end-user exception in Dodd-Frank, with the lowest level of required regulatory reporting burden imposed by this law. The Company is currently complying with these enacted regulations and intends to comply with regulations enacted in the future, but cannot predict when the final regulations will be issued or what requirements they will impose.
50
December 31, 2011 Expected Maturity Date Millions of dollars 2012 2013 2014 2015 2016 Thereafter Total Fair Value Long-Term Debt: Fixed Rate ($) 269.9 160.7 44.8 8.4 7.7 3,990.0 4,481.5 5,330.1 Average Fixed Interest Rate (%) 6.19 7.00 4.96 5.50 5.54 5.84 5.89 — Variable Rate ($) 4.4 4.4 4.4 4.4 4.4 147.5 169.5 147.1 Average Variable Interest Rate (%) 1.23 1.23 1.23 1.23 1.23 0.74 0.80 — Interest Rate Swaps: Pay Variable/Receive Fixed ($) 253.2 — — — — — 253.2 0.3 Pay Interest Rate (%) 5.07 — — — — — 5.07 — Receive Interest Rate (%) 6.28 — — — — — 6.28 — Pay Fixed/Receive Variable ($) 504.4 154.4 4.4 4.4 4.4 150.6 822.6 (156.5 ) Average Pay Interest Rate (%) 3.41 4.92 6.17 6.17 6.17 4.80 3.99 — Average Receive Interest Rate (%) .59 .60 1.23 1.23 1.23 .70 .62 — December 31, 2010 Expected Maturity Date Millions of dollars 2011 2012 2013 2014 2015 Thereafter Total Fair Value Long-Term Debt: Fixed Rate ($) 623.0 268.6 159.8 43.7 7.8 3,196.6 4,299.5 4,666.0 Average Fixed Interest Rate (%) 6.76 6.20 7.02 4.97 5.48 6.07 6.20 — Variable Rate ($) 4.4 4.4 4.4 4.4 4.4 155.0 177.0 162.7 Average Variable Interest Rate (%) 1.00 1.00 1.00 1.00 1.00 .72 .76 — Interest Rate Swaps: Pay Variable/Receive Fixed ($) 303.2 253.2 — — — — 556.4 4.0 Pay Interest Rate (%) 6.02 4.92 — — — — 5.52 — Receive Interest Rate (%) 6.89 6.28 — — — — 6.62 — Pay Fixed/Receive Variable ($) 654.4 254.4 4.4 4.4 4.4 155.0 1,077.0 (77.5 ) Average Pay Interest Rate (%) 4.59 4.21 6.17 6.17 6.17 4.84 4.56 — Average Receive Interest Rate (%) .31 .31 1.00 1.00 1.00 .68 .37 — All financial instruments held by the Company described below are held for purposes other than trading.Interest Rate RiskThe tables below provides information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average interest rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.December 31, 2013 Expected Maturity Date Millions of dollars 2014 2015 2016 2017 2018 Thereafter Total Fair Value Long-Term Debt: Fixed Rate ($) 46.7 10.8 109.6 8.7 717.9 4,386.5 5,280.2 5,753.3 Average Fixed Interest Rate (%) 4.83 4.72 1.14 4.84 5.95 5.43 5.40 — Variable Rate ($) 4.4 4.4 4.4 4.4 4.4 138.2 160.2 154.4 Average Variable Interest Rate (%) 0.94 0.94 0.94 0.94 0.94 0.53 0.59 — Interest Rate Swaps: Pay Fixed/Receive Variable ($) 604.4 654.4 4.4 4.4 4.4 141.8 1,413.8 13.0 Average Pay Interest Rate (%) 3.97 4.17 6.17 6.17 6.17 4.72 4.16 — Average Receive Interest Rate (%) 0.25 0.25 0.94 0.94 0.94 0.49 0.28 — December 31, 2012 Expected Maturity Date Millions of dollars 2013 2014 2015 2016 2017 Thereafter Total Fair Value Long-Term Debt: Fixed Rate ($) 162.0 46.1 9.8 8.6 7.7 4,706.0 4,940.2 5,941.4 Average Fixed Interest Rate (%) 6.96 4.86 4.92 5.03 5.12 5.59 5.63 — Variable Rate ($) 4.4 4.4 4.4 4.4 4.4 142.6 164.6 157.5 Average Variable Interest Rate (%) 1.01 1.01 1.01 1.01 1.01 0.61 0.66 — Interest Rate Swaps: Pay Fixed/Receive Variable ($) 604.4 304.4 4.4 4.4 4.4 146.2 1,068.2 (33.6 ) Average Pay Interest Rate (%) 3.04 2.53 6.17 6.17 6.17 4.76 3.17 — Average Receive Interest Rate (%) 0.31 0.32 1.01 1.01 1.01 0.58 0.36 — While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.The above tables exclude long-term debt of $15$3 million at December 31, 20112013 and $21$9 million at December 31, 2010,2012, which amounts do not have a stated interest rate associated with them.46For further discussion of the Company’s long-term debt and interest rate derivatives, see ITEMItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — LIQUIDITY AND CAPITAL RESOURCESLiquidity and alsoCapital Resources and Notes 4 and 6 ofto the condensed consolidated financial statements.
Commodity Price Risk
Expected Maturity:
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Future Contracts |
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| Purchased |
| Sold |
| Sold |
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| Long |
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| (Short) |
| (Short) |
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2012 |
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Settlement Price(a) |
| 3.12 |
| 3.90 |
| Strike Price(a) |
| 4.63 |
| 3.75 |
| 5.00 |
| 3.75 |
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Contract Amount(b) |
| 17.0 |
| 0.2 |
| Contract Amount(b) |
| 38.7 |
| 0.2 |
| 0.2 |
| 0.2 |
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Fair Value(b) |
| 13.5 |
| 0.3 |
| Fair Value(b) |
| 0.4 |
| — |
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| — |
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2013 |
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Settlement Price(a) |
| 3.88 |
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| 4.60 |
| — |
| — |
| — |
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Contract Amount(b) |
| 1.4 |
| — |
| Contract Amount(b) |
| 3.5 |
| — |
| — |
| — |
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Fair Value(b) |
| 1.2 |
| — |
| Fair Value(b) |
| 0.2 |
| — |
| — |
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| 2014 | Long | Short | 2014 | (Long) | (Short) | ||||||
| Settlement Price (a) | 4.18 | 4.17 | Strike Price (a) | 4.01 | 4.10 | ||||||
| Contract Amount (b) | 13.0 | 0.7 | Contract Amount (b) | 26.6 | 0.2 | ||||||
| Fair Value (b) | 14.0 | 0.7 | Fair Value (b) | 2.2 | — | ||||||
| 2015 | 2015 | ||||||||||
| Settlement Price (a) | 4.27 | 4.1 | Strike Price (a) | 4.30 | — | ||||||
| Contract Amount (b) | 1.1 | 0.2 | Contract Amount (b) | 0.1 | — | ||||||
| Fair Value (b) | 1.2 | 0.2 | Fair Value (b) | — | — | ||||||
Swaps |
| 2012 |
| 2013 |
| 2014 |
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Commodity Swaps: |
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Pay fixed/receive variable(b) |
| 86.2 |
| 24.4 |
| 11.7 |
| 11.6 |
| 5.1 |
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Average pay rate(a) |
| 4.2928 |
| 5.5068 |
| 5.3603 |
| 5.3764 |
| 5.3088 |
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Average received rate(a) |
| 3.1876 |
| 3.9337 |
| 4.3395 |
| 4.5970 |
| 4.8541 |
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Fair Value(b) |
| 64.0 |
| 17.4 |
| 9.5 |
| 9.9 |
| 4.7 |
|
Pay variable/receive fixed(b) |
| 48.5 |
| 14.3 |
| 9.4 |
| 9.9 |
| 4.7 |
|
Average pay rate(a) |
| 3.2090 |
| 3.9361 |
| 4.3395 |
| 4.5970 |
| 4.8541 |
|
Average received rate(a) |
| 4.2887 |
| 5.3655 |
| 5.3867 |
| 5.3867 |
| 5.3163 |
|
Fair Value(b) |
| 64.9 |
| 19.5 |
| 11.6 |
| 11.6 |
| 5.1 |
|
Basis Swaps: |
|
|
|
|
|
|
|
|
|
|
|
Pay variable/receive variable(b) |
| 26.2 |
| 5.9 |
| — |
| — |
| — |
|
Average pay rate(a) |
| 3.2342 |
| 3.9336 |
| — |
| — |
| — |
|
Average received rate(a) |
| 3.2102 |
| 3.8825 |
| — |
| — |
| — |
|
Fair Value(b) |
| 26.1 |
| 5.9 |
| — |
| — |
| — |
|
| Swaps | 2014 | 2015 | 2016 | 2017 | |||||||||
| Commodity Swaps: | |||||||||||||
| Pay fixed/receive variable (b) | 51.9 | 17.1 | 10.0 | 1.0 | |||||||||
| Average pay rate (a) | 4.2063 | 4.9039 | 4.7098 | 4.1275 | |||||||||
| Average received rate (a) | 4.1774 | 4.1634 | 4.1284 | 4.1530 | |||||||||
| Fair Value (b) | 51.6 | 14.5 | 8.8 | 1.1 | |||||||||
| Pay variable/receive fixed (b) | 32.4 | 14.0 | 8.7 | 1.1 | |||||||||
| Average pay rate (a) | 4.1720 | 4.1621 | 4.1296 | 4.1530 | |||||||||
| Average received rate (a) | 4.2845 | 4.9363 | 4.7143 | 4.1325 | |||||||||
| Fair Value (b) | 33.3 | 16.6 | 9.9 | 1.1 | |||||||||
| Basis Swaps: | |||||||||||||
| Pay variable/receive variable (b) | 1.0 | 0.5 | — | — | |||||||||
| Average pay rate (a) | 4.2256 | 4.3982 | — | — | |||||||||
| Average received rate (a) | 4.1700 | 4.3767 | — | — | |||||||||
| Fair Value (b) | 1.0 | 0.5 | — | — | |||||||||
SCE&G and
52
Charlotte, North Carolina February To the Board of Directors and Stockholders ofSCANA CorporationCayce, South CarolinaWe have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the “Company”"Company") as of December 31, 20112013 and 2010,2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in common equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011.2013. 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’sCompany'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, 20112013 and 2010,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011,2013, 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’sCompany's internal control over financial reporting as of December 31, 2011,2013, based on the criteria established in Internal Control—IntegratedControl-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012,28, 2014 expressed an unqualified opinion on the Company’sCompany's internal control over financial reporting./s/DELOITTE & TOUCHE LLP 29, 20125348
December 31, (Millions of dollars) |
| 2011 |
| 2010 |
| ||
Assets |
|
|
|
|
| ||
Utility Plant In Service |
| $ | 12,000 |
| $ | 11,714 |
|
Accumulated Depreciation and Amortization |
| (3,836 | ) | (3,495 | ) | ||
Construction Work in Progress |
| 1,482 |
| 1,081 |
| ||
Nuclear Fuel, Net of Accumulated Amortization |
| 171 |
| 132 |
| ||
Goodwill, Net of Writedown of $276 |
| 230 |
| 230 |
| ||
|
|
|
|
|
| ||
Utility Plant, Net |
| 10,047 |
| 9,662 |
| ||
|
|
|
|
|
| ||
Nonutility Property and Investments: |
|
|
|
|
| ||
Nonutility property, net of accumulated depreciation of $131 and $118 |
| 305 |
| 299 |
| ||
Assets held in trust, net-nuclear decommissioning |
| 84 |
| 76 |
| ||
Other investments |
| 87 |
| 78 |
| ||
Nonutility Property and Investments, Net |
| 476 |
| 453 |
| ||
|
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash and cash equivalents |
| 29 |
| 55 |
| ||
Receivables, net of allowance for uncollectible accounts of $6 and $9 |
| 756 |
| 837 |
| ||
Inventories (at average cost): |
|
|
|
|
| ||
Fuel |
| 313 |
| 316 |
| ||
Materials and supplies |
| 129 |
| 125 |
| ||
Emission allowances |
| 2 |
| 6 |
| ||
Prepayments and other |
| 236 |
| 271 |
| ||
Deferred income taxes |
| 26 |
| 21 |
| ||
Total Current Assets |
| 1,491 |
| 1,631 |
| ||
|
|
|
|
|
| ||
Deferred Debits and Other Assets: |
|
|
|
|
| ||
Regulatory assets |
| 1,279 |
| 1,061 |
| ||
Other |
| 241 |
| 161 |
| ||
Total Deferred Debits and Other Assets |
| 1,520 |
| 1,222 |
| ||
|
|
|
|
|
| ||
Total |
| $ | 13,534 |
| $ | 12,968 |
|
| December 31, (Millions of dollars) | 2013 | 2012 | ||||||
| Assets | ||||||||
| Utility Plant In Service | $ | 12,213 | $ | 11,865 | ||||
| Accumulated Depreciation and Amortization | (4,011 | ) | (3,811 | ) | ||||
| Construction Work in Progress | 2,724 | 2,084 | ||||||
| Plant to be Retired, Net | 177 | 362 | ||||||
| Nuclear Fuel, Net of Accumulated Amortization | 310 | 166 | ||||||
| Goodwill | 230 | 230 | ||||||
| Utility Plant, Net | 11,643 | 10,896 | ||||||
| Nonutility Property and Investments: | ||||||||
| Nonutility property, net of accumulated depreciation of $150 and $139 | 317 | 306 | ||||||
| Assets held in trust, net-nuclear decommissioning | 101 | 94 | ||||||
| Other investments | 86 | 87 | ||||||
| Nonutility Property and Investments, Net | 504 | 487 | ||||||
| Current Assets: | ||||||||
| Cash and cash equivalents | 136 | 72 | ||||||
| Receivables, net of allowance for uncollectible accounts of $6 and $7 | 802 | 780 | ||||||
| Inventories: | ||||||||
| Fuel | 231 | 304 | ||||||
| Materials and supplies | 131 | 136 | ||||||
| Emission allowances | 1 | 1 | ||||||
| Prepayments and other | 120 | 223 | ||||||
| Deferred income taxes | — | 11 | ||||||
| Total Current Assets | 1,421 | 1,527 | ||||||
| Deferred Debits and Other Assets: | ||||||||
| Regulatory assets | 1,360 | 1,464 | ||||||
| Pension asset | 47 | — | ||||||
| Other | 189 | 242 | ||||||
| Total Deferred Debits and Other Assets | 1,596 | 1,706 | ||||||
| Total | $ | 15,164 | $ | 14,616 | ||||
54
December 31, (Millions of dollars) |
| 2011 |
| 2010 |
| ||
Capitalization and Liabilities |
|
|
|
|
| ||
Common equity |
| $ | 3,889 |
| $ | 3,702 |
|
Long-Term Debt, Net |
| 4,622 |
| 4,152 |
| ||
Total Capitalization |
| 8,511 |
| 7,854 |
| ||
Current Liabilities: |
|
|
|
|
| ||
Short-term borrowings |
| 653 |
| 420 |
| ||
Current portion of long-term debt |
| 31 |
| 337 |
| ||
Accounts payable |
| 374 |
| 526 |
| ||
Customer deposits and customer prepayments |
| 103 |
| 100 |
| ||
Taxes accrued |
| 154 |
| 146 |
| ||
Interest accrued |
| 74 |
| 72 |
| ||
Dividends declared |
| 63 |
| 61 |
| ||
Derivative financial instruments |
| 77 |
| 65 |
| ||
Other |
| 113 |
| 140 |
| ||
Total Current Liabilities |
| 1,642 |
| 1,867 |
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Deferred income taxes, net |
| 1,533 |
| 1,391 |
| ||
Deferred investment tax credits |
| 40 |
| 56 |
| ||
Asset retirement obligations |
| 474 |
| 497 |
| ||
Pension and other postretirement benefits |
| 291 |
| 202 |
| ||
Regulatory liabilities |
| 778 |
| 913 |
| ||
Other |
| 265 |
| 188 |
| ||
Total Deferred Credits and Other Liabilities |
| 3,381 |
| 3,247 |
| ||
Commitments and Contingencies (Note 10) |
| — |
| — |
| ||
Total |
| $ | 13,534 |
| $ | 12,968 |
|
| December 31, (Millions of dollars) | 2013 | 2012 | ||||||
| Capitalization and Liabilities | ||||||||
| Common equity | $ | 4,664 | $ | 4,154 | ||||
| Long-Term Debt, Net | 5,395 | 4,949 | ||||||
| Total Capitalization | 10,059 | 9,103 | ||||||
| Current Liabilities: | ||||||||
| Short-term borrowings | 376 | 623 | ||||||
| Current portion of long-term debt | 54 | 172 | ||||||
| Accounts payable | 425 | 428 | ||||||
| Customer deposits and customer prepayments | 88 | 86 | ||||||
| Taxes accrued | 206 | 164 | ||||||
| Interest accrued | 82 | 82 | ||||||
| Dividends declared | 69 | 66 | ||||||
| Derivative financial instruments | 8 | 80 | ||||||
| Other | 134 | 110 | ||||||
| Total Current Liabilities | 1,442 | 1,811 | ||||||
| Deferred Credits and Other Liabilities: | ||||||||
| Deferred income taxes, net | 1,703 | 1,653 | ||||||
| Deferred investment tax credits | 32 | 36 | ||||||
| Asset retirement obligations | 576 | 561 | ||||||
| Postretirement benefits | 227 | 387 | ||||||
| Regulatory liabilities | 966 | 882 | ||||||
| Other | 159 | 183 | ||||||
| Total Deferred Credits and Other Liabilities | 3,663 | 3,702 | ||||||
| Commitments and Contingencies (Note 10) | — | — | ||||||
| Total | $ | 15,164 | $ | 14,616 | ||||
55
Years Ended December 31, (Millions of dollars, except per share amounts) |
| 2011 |
| 2010 |
| 2009 |
| |||
Operating Revenues: |
|
|
|
|
|
|
| |||
Electric |
| $ | 2,424 |
| $ | 2,367 |
| $ | 2,141 |
|
Gas-regulated |
| 849 |
| 989 |
| 958 |
| |||
Gas-nonregulated |
| 1,136 |
| 1,245 |
| 1,138 |
| |||
Total Operating Revenues |
| 4,409 |
| 4,601 |
| 4,237 |
| |||
|
|
|
|
|
|
|
| |||
Operating Expenses: |
|
|
|
|
|
|
| |||
Fuel used in electric generation |
| 917 |
| 942 |
| 818 |
| |||
Purchased power |
| 19 |
| 17 |
| 17 |
| |||
Gas purchased for resale |
| 1,455 |
| 1,679 |
| 1,570 |
| |||
Other operation and maintenance |
| 658 |
| 670 |
| 640 |
| |||
Depreciation and amortization |
| 346 |
| 335 |
| 316 |
| |||
Other taxes |
| 201 |
| 190 |
| 177 |
| |||
Total Operating Expenses |
| 3,596 |
| 3,833 |
| 3,538 |
| |||
|
|
|
|
|
|
|
| |||
Operating Income |
| 813 |
| 768 |
| 699 |
| |||
|
|
|
|
|
|
|
| |||
Other Income (Expense): |
|
|
|
|
|
|
| |||
Other income |
| 52 |
| 52 |
| 67 |
| |||
Other expenses |
| (40 | ) | (39 | ) | (37 | ) | |||
Interest charges, net of allowance for borrowed funds used during construction of $7, $10 and $23 |
| (284 | ) | (266 | ) | (233 | ) | |||
Allowance for equity funds used during construction |
| 14 |
| 20 |
| 28 |
| |||
Total Other Expense |
| (258 | ) | (233 | ) | (175 | ) | |||
|
|
|
|
|
|
|
| |||
Income Before Income Tax Expense |
| 555 |
| 535 |
| 524 |
| |||
Income Tax Expense |
| 168 |
| 159 |
| 167 |
| |||
Net Income |
| 387 |
| 376 |
| 357 |
| |||
Less Preferred Stock Dividends of Subsidiary |
| — |
| — |
| (9 | ) | |||
Income Available to Common Shareholders of SCANA |
| $ | 387 |
| $ | 376 |
| $ | 348 |
|
|
|
|
|
|
|
|
| |||
Per Common Share Data |
|
|
|
|
|
|
| |||
Basic Earnings Per Share of Common Stock |
| $ | 3.01 |
| $ | 2.99 |
| $ | 2.85 |
|
Diluted Earnings Per Share of Common Stock |
| 2.97 |
| 2.98 |
| 2.85 |
| |||
Weighted Average Common Shares Outstanding (millions) |
|
|
|
|
|
|
| |||
Basic |
| 128.8 |
| 125.7 |
| 122.1 |
| |||
Diluted |
| 130.2 |
| 126.3 |
| 122.2 |
| |||
Dividends Declared Per Share of Common Stock |
| $ | 1.94 |
| $ | 1.90 |
| $ | 1.88 |
|
| Years Ended December 31, (Millions of dollars, except per share amounts) | 2013 | 2012 | 2011 | |||||||||
| Operating Revenues: | ||||||||||||
| Electric | $ | 2,423 | $ | 2,446 | $ | 2,424 | ||||||
| Gas-regulated | 955 | 774 | 849 | |||||||||
| Gas-nonregulated | 1,117 | 956 | 1,136 | |||||||||
| Total Operating Revenues | 4,495 | 4,176 | 4,409 | |||||||||
| Operating Expenses: | ||||||||||||
| Fuel used in electric generation | 745 | 838 | 917 | |||||||||
| Purchased power | 43 | 28 | 19 | |||||||||
| Gas purchased for resale | 1,491 | 1,198 | 1,455 | |||||||||
| Other operation and maintenance | 708 | 690 | 658 | |||||||||
| Depreciation and amortization | 378 | 356 | 346 | |||||||||
| Other taxes | 220 | 207 | 201 | |||||||||
| Total Operating Expenses | 3,585 | 3,317 | 3,596 | |||||||||
| Operating Income | 910 | 859 | 813 | |||||||||
| Other Income (Expense): | ||||||||||||
| Other income | 100 | 59 | 52 | |||||||||
| Other expenses | (46 | ) | (42 | ) | (40 | ) | ||||||
| Interest charges, net of allowance for borrowed funds used during construction of $14, $11 and $7 | (297 | ) | (295 | ) | (284 | ) | ||||||
| Allowance for equity funds used during construction | 27 | 21 | 14 | |||||||||
| Total Other Expense | (216 | ) | (257 | ) | (258 | ) | ||||||
| Income Before Income Tax Expense | 694 | 602 | 555 | |||||||||
| Income Tax Expense | 223 | 182 | 168 | |||||||||
| Net Income | $ | 471 | $ | 420 | $ | 387 | ||||||
| Per Common Share Data | ||||||||||||
| Basic Earnings Per Share of Common Stock | $ | 3.40 | $ | 3.20 | $ | 3.01 | ||||||
| Diluted Earnings Per Share of Common Stock | 3.39 | 3.15 | 2.97 | |||||||||
| Weighted Average Common Shares Outstanding (millions) | ||||||||||||
| Basic | 138.7 | 131.1 | 128.8 | |||||||||
| Diluted | 139.1 | 133.3 | 130.2 | |||||||||
56
SCANA Corporation
| Years Ended December 31, (Millions of dollars) | 2013 | 2012 | 2011 | ||||||||||
| Net Income | $ | 471 | $ | 420 | $ | 387 | |||||||
| 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 $4, $(5) and $(36) | 7 | (8 | ) | (58 | ) | ||||||||
| Losses on cash flow hedging activities reclassified to net income, net of tax of $7, $12 and $8 | 11 | 19 | 13 | ||||||||||
| Net unrealized gains (losses) on cash flow hedging activities | 18 | 11 | (45 | ) | |||||||||
| Deferred Costs of Employee Benefit Plans: | |||||||||||||
| Deferred costs of employee benefit plans, net of tax of $4, $(2) and $(2) | 7 | (4 | ) | (3 | ) | ||||||||
| Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $-, $- and $- | 1 | 1 | 1 | ||||||||||
| Net deferred costs of employee benefit plans | 8 | (3 | ) | (2 | ) | ||||||||
| Other Comprehensive Income (Loss) | 26 | 8 | (47 | ) | |||||||||
| Total Comprehensive Income | $ | 497 | $ | 428 | $ | 340 | |||||||
For the Years Ended December 31, (Millions of dollars) |
| 2011 |
| 2010 |
| 2009 |
| ||||
Cash Flows From Operating Activities: |
|
|
|
|
|
|
| ||||
Net Income |
| $ | 387 |
| $ | 376 |
| $ | 357 |
| |
Adjustments to reconcile net income to net cash provided from operating activities: |
|
|
|
|
|
|
| ||||
Earnings from equity method investments, net of distributions |
| 2 |
| 3 |
| 1 |
| ||||
Deferred income taxes, net |
| 164 |
| 240 |
| 93 |
| ||||
Depreciation and amortization |
| 354 |
| 341 |
| 329 |
| ||||
Amortization of nuclear fuel |
| 40 |
| 36 |
| 18 |
| ||||
Allowance for equity funds used during construction |
| (14 | ) | (20 | ) | (28 | ) | ||||
Carrying cost recovery |
| — |
| (3 | ) | (5 | ) | ||||
Cash provided (used) by changes in certain assets and liabilities: |
|
|
|
|
|
|
| ||||
Receivables |
| 34 |
| (143 | ) | 134 |
| ||||
Inventories |
| (44 | ) | 11 |
| (76 | ) | ||||
Prepayments and other |
| 58 |
| (109 | ) | 64 |
| ||||
Regulatory assets |
| (173 | ) | (71 | ) | (82 | ) | ||||
Regulatory liabilities |
| (17 | ) | (13 | ) | (6 | ) | ||||
Accounts payable |
| (99 | ) | 79 |
| (46 | ) | ||||
Taxes accrued |
| 8 |
| 12 |
| 6 |
| ||||
Interest accrued |
| 2 |
| 1 |
| 2 |
| ||||
Changes in other assets |
| 34 |
| (32 | ) | (36 | ) | ||||
Changes in other liabilities |
| 75 |
| 103 |
| (46 | ) | ||||
Net Cash Provided From Operating Activities |
| 811 |
| 811 |
| 679 |
| ||||
Cash Flows From Investing Activities: |
|
|
|
|
|
|
| ||||
Property additions and construction expenditures |
| (884 | ) | (876 | ) | (914 | ) | ||||
Proceeds from investments (including derivative collateral posted) |
| 36 |
| 104 |
| 31 |
| ||||
Purchase of investments (including derivative collateral posted) |
| (168 | ) | (102 | ) | (6 | ) | ||||
Settlements of interest rate contracts |
| (61 | ) | — |
| — |
| ||||
Net Cash Used For Investing Activities |
| (1,077 | ) | (874 | ) | (889 | ) | ||||
Cash Flows From Financing Activities: |
|
|
|
|
|
|
| ||||
Proceeds from issuance of common stock |
| 97 |
| 149 |
| 191 |
| ||||
Proceeds from issuance of long-term debt |
| 826 |
| 259 |
| 600 |
| ||||
Repayments of long-term debt |
| (668 | ) | (300 | ) | (599 | ) | ||||
Redemption/repurchase of equity securities |
| — |
| — |
| (113 | ) | ||||
Dividends |
| (248 | ) | (237 | ) | (234 | ) | ||||
Short-term borrowings, net |
| 233 |
| 85 |
| 255 |
| ||||
Net Cash Provided From (Used For) Financing Activities |
| 240 |
| (44 | ) | 100 |
| ||||
Net Decrease in Cash and Cash Equivalents |
| (26 | ) | (107 | ) | (110 | ) | ||||
Cash and Cash Equivalents, January 1 |
| 55 |
| 162 |
| 272 |
| ||||
Cash and Cash Equivalents, December 31 |
| $ | 29 |
| $ | 55 |
| $ | 162 |
| |
Supplemental Cash Flow Information: |
|
|
|
|
|
|
| ||||
Cash paid for—Interest (net of capitalized interest of $7, $9 and $23) |
| $ | 276 |
| $ | 268 |
| $ | 233 |
| |
| —Income taxes |
| 6 |
| 61 |
| 79 |
| |||
Noncash Investing and Financing Activities: |
|
|
|
|
|
|
| ||||
Accrued construction expenditures |
| 85 |
| 179 |
| 160 |
| ||||
Capital leases |
| 6 |
| 6 |
| — |
| ||||
| For the Years Ended December 31, (Millions of dollars) | 2013 | 2012 | 2011 | |||||||||
| Cash Flows From Operating Activities: | ||||||||||||
| Net Income | $ | 471 | $ | 420 | $ | 387 | ||||||
| Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||||||
| Earnings from equity method investments, net of distributions | 7 | — | 2 | |||||||||
| Deferred income taxes, net | 49 | 130 | 164 | |||||||||
| Depreciation and amortization | 393 | 368 | 354 | |||||||||
| Amortization of nuclear fuel | 57 | 44 | 40 | |||||||||
| Allowance for equity funds used during construction | (27 | ) | (21 | ) | (14 | ) | ||||||
| Carrying cost recovery | (3 | ) | — | — | ||||||||
| Changes in certain assets and liabilities: | ||||||||||||
| Receivables | (38 | ) | 5 | 34 | ||||||||
| Inventories | 21 | (53 | ) | (44 | ) | |||||||
| Prepayments and other | (12 | ) | 3 | 58 | ||||||||
| Regulatory assets | 113 | (172 | ) | (173 | ) | |||||||
| Regulatory liabilities | 56 | 62 | (17 | ) | ||||||||
| Accounts payable | 24 | 34 | (99 | ) | ||||||||
| Taxes accrued | 42 | 10 | 8 | |||||||||
| Interest accrued | — | 8 | 2 | |||||||||
| Pension and other postretirement benefits | (217 | ) | 89 | 90 | ||||||||
| Other assets | 78 | (120 | ) | 34 | ||||||||
| Other liabilities | 36 | 32 | (15 | ) | ||||||||
| Net Cash Provided From Operating Activities | 1,050 | 839 | 811 | |||||||||
| Cash Flows From Investing Activities: | ||||||||||||
| Property additions and construction expenditures | (1,106 | ) | (1,077 | ) | (884 | ) | ||||||
| Proceeds from investments (including derivative collateral posted) | 222 | 472 | 36 | |||||||||
| Purchase of investments (including derivative collateral posted) | (176 | ) | (414 | ) | (168 | ) | ||||||
| Payments upon interest rate derivative contract settlement | (49 | ) | (51 | ) | (61 | ) | ||||||
| Proceeds from interest rate derivative contract settlement | 163 | 14 | — | |||||||||
| Net Cash Used For Investing Activities | (946 | ) | (1,056 | ) | (1,077 | ) | ||||||
| Cash Flows From Financing Activities: | ||||||||||||
| Proceeds from issuance of common stock | 295 | 97 | 97 | |||||||||
| Proceeds from issuance of long-term debt | 451 | 759 | 826 | |||||||||
| Repayments of long-term debt | (258 | ) | (309 | ) | (668 | ) | ||||||
| Dividends | (281 | ) | (257 | ) | (248 | ) | ||||||
| Short-term borrowings, net | (247 | ) | (30 | ) | 233 | |||||||
| Net Cash Provided From (Used For) Financing Activities | (40 | ) | 260 | 240 | ||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 64 | 43 | (26 | ) | ||||||||
| Cash and Cash Equivalents, January 1 | 72 | 29 | 55 | |||||||||
| Cash and Cash Equivalents, December 31 | $ | 136 | $ | 72 | $ | 29 | ||||||
| Supplemental Cash Flow Information: | ||||||||||||
| Cash paid for—Interest (net of capitalized interest of $14, $11 and $7) | $ | 288 | $ | 281 | $ | 276 | ||||||
| —Income taxes | 104 | 107 | 6 | |||||||||
| Noncash Investing and Financing Activities: | ||||||||||||
| Accrued construction expenditures | 111 | 124 | 85 | |||||||||
| Capital leases | 6 | 8 | 6 | |||||||||
| Nuclear fuel purchase | 98 | — | — | |||||||||
57
| Accumulated | |||||||||||||||||||
| Other | |||||||||||||||||||
| Common Stock | Retained | Comprehensive | |||||||||||||||||
| Millions | Shares | Amount | Earnings | Loss | Total | ||||||||||||||
| Balance as of January 1, 2011 | 127 | $ | 1,789 | $ | 1,960 | $ | (47 | ) | $ | 3,702 | |||||||||
| Net Income | 387 | 387 | |||||||||||||||||
| Other Comprehensive Loss, net of taxes of $(29) | (47 | ) | (47 | ) | |||||||||||||||
| Total Comprehensive Income (Loss) | 387 | (47 | ) | 340 | |||||||||||||||
| Issuance of Common Stock | 3 | 97 | 97 | ||||||||||||||||
| Dividends Declared | (250 | ) | (250 | ) | |||||||||||||||
| Balance as of December 31, 2011 | 130 | 1,886 | 2,097 | (94 | ) | 3,889 | |||||||||||||
| Net Income | 420 | 420 | |||||||||||||||||
| Other Comprehensive Income, net of taxes of $5 | 8 | 8 | |||||||||||||||||
| Total Comprehensive Income | 420 | 8 | 428 | ||||||||||||||||
| Issuance of Common Stock | 2 | 97 | 97 | ||||||||||||||||
| Dividends Declared | (260 | ) | (260 | ) | |||||||||||||||
| Balance as of December 31, 2012 | 132 | 1,983 | 2,257 | (86 | ) | 4,154 | |||||||||||||
| Net Income | 471 | 471 | |||||||||||||||||
| Other Comprehensive Income, net of taxes of $16 | 26 | 26 | |||||||||||||||||
| Total Comprehensive Income | 471 | 26 | 497 | ||||||||||||||||
| Issuance of Common Stock | 9 | 297 | 297 | ||||||||||||||||
| Dividends Declared | (284 | ) | (284 | ) | |||||||||||||||
| Balance as of December 31, 2013 | 141 | $ | 2,280 | $ | 2,444 | $ | (60 | ) | $ | 4,664 | |||||||||
COMPREHENSIVE INCOME$2.03
|
| Common Stock |
| Retained |
| Accumulated |
|
|
| ||||||
Millions |
| Shares |
| Amount |
| Earnings |
| Income (Loss) |
| Total |
| ||||
Balance as of January 1, 2009 |
| 118 |
| $ | 1,449 |
| $ | 1,705 |
| $ | (109 | ) | $ | 3,045 |
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
| ||||
Income available to common shareholders of SCANA |
|
|
|
|
| 348 |
|
|
| 348 |
| ||||
Other comprehensive income, net of taxes $33 |
|
|
|
|
|
|
| 54 |
| 54 |
| ||||
Total Comprehensive Income |
|
|
|
|
| 348 |
| 54 |
| 402 |
| ||||
Issuance of Common Stock |
| 5 |
| 191 |
|
|
|
|
| 191 |
| ||||
Dividends Declared on Common Stock |
|
|
|
|
| (230 | ) |
|
| (230 | ) | ||||
Balance as of December 31, 2009 |
| 123 |
| $ | 1,640 |
| $ | 1,823 |
| $ | (55 | ) | $ | 3,408 |
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
| ||||
Income available to common shareholders of SCANA |
|
|
|
|
| 376 |
|
|
| 376 |
| ||||
Other comprehensive income, net of taxes $5 |
|
|
|
|
|
|
| 8 |
| 8 |
| ||||
Total Comprehensive Income |
|
|
|
|
| 376 |
| 8 |
| 384 |
| ||||
Issuance of Common Stock |
| 4 |
| 149 |
|
|
|
|
| 149 |
| ||||
Dividends Declared on Common Stock |
|
|
|
|
| (239 | ) |
|
| (239 | ) | ||||
Balance as of December 31, 2010 |
| 127 |
| $ | 1,789 |
| $ | 1,960 |
| $ | (47 | ) | $ | 3,702 |
|
Comprehensive Income (Loss): |
|
|
|
|
|
|
|
|
|
|
| ||||
Income available to common shareholders of SCANA |
|
|
|
|
| 387 |
|
|
| 387 |
| ||||
Other comprehensive loss, net of taxes $(29) |
|
|
|
|
|
|
| (47 | ) | (47 | ) | ||||
Total Comprehensive Income (Loss) |
|
|
|
|
| 387 |
| (47 | ) | 340 |
| ||||
Issuance of Common Stock |
| 3 |
| 97 |
|
|
|
|
| 97 |
| ||||
Dividends Declared on Common Stock |
|
|
|
|
| (250 | ) |
|
| (250 | ) | ||||
Balance as of December 31, 2011 |
| 130 |
| $ | 1,886 |
| $ | 2,097 |
| $ | (94 | ) | $ | 3,889 |
|
, $1.98 and $1.94 for 2013, 2012 and 2011, respectively.
58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Communications, Inc. South Carolina Generating Company, Inc. ServiceCare, Inc. Public Service Company of North Carolina, Incorporated SCANA Services, Inc. Carolina Gas Transmission Corporation SCANA Corporate Security Services, Inc. 2011 2010 2009 SCE&G 2.92 % 2.83 % 2.97 % GENCO 2.69 % 2.66 % 2.66 % CGT 2.00 % 1.94 % 1.94 % PSNC Energy 3.05 % 3.11 % 3.10 % Aggregate of Above 2.90 % 2.85 % 2.95 % 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. Unit 1 New Units As of December 31, 2011 Percent owned 66.7 % 55.0 % Plant in service $ 1.0 billion — Accumulated depreciation $ 545.0 million — Construction work in progress $ 71.0 million $ 1.2 billion As of December 31, 2010 Percent owned 66.7 % 55.0 % Plant in service $ 1.0 billion — Accumulated depreciation $ 548.8 million — Construction work in progress $ 40.1 million $ 891.2 million 10. 2012. 2020. The Company considers amounts categorized by FERC as “acquisition adjustments” with carrying values 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 and fuel oil. 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. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC. 2015. expense as incurred.1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESOrganization and Principles of ConsolidationSCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company also conducts other energy-related business and provides fiber optic communications in South Carolina.The accompanying Consolidated Financial Statementsconsolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries, and two other wholly-owned subsidiaries liquidated in 2011.subsidiaries.Regulated businessesNonregulated businessesRegulated businesses Nonregulated businesses South Carolina Electric & Gas Company Westex Holdings, LLCThe Company reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance.Use of EstimatesThe preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.Utility PlantUtility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction,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 6.9% for 2013, 6.3% for 2012 and 4.7% for 2011, 7.4% for 2010 and 7.5% for 2009.2011. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561.rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.55The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows: 2013 2012 2011 SCE&G 2.96 % 2.93 % 2.92 % GENCO 2.66 % 2.66 % 2.69 % CGT 2.19 % 2.09 % 2.00 % PSNC Energy 3.01 % 3.01 % 3.05 % Aggregate of Above 2.93 % 2.90 % 2.90 % Jointly Owned Utility PlantSCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses areis included in the corresponding operating expenses on its income statement.As of December 31, 2013 2012 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.1 billion — $ 1.1 billion — Accumulated depreciation $566.9 million — $557.0 million — Construction work in progress $127.1 million $2.3 billion $113.6 million $1.8 billion SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0$5.4 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-yearone-year and five year-year escalation rates as required by the SCPSC.SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent For a discussion of the output ofwhen the New Units. As previously reported,Units are expected to be placed in service, and a description of SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation&G's agreement to acquire an additional 5% ownership in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units, and unanticipated rock conditions at the site. These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium. While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million. SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (seesee Note 2 to the consolidated financial statements), will be recoverable through rates.Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6$75.6 million at December 31, 20112013 and $77.9$92.9 million at December 31, 2010.Plant to be RetiredAs previously disclosed, in 2012 SCE&G identified a total of six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. As of December 31, 2013, three of these units had been retired and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.56Major MaintenancePlanned 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 are classified as a regulatory asset or regulatory liability on the consolidated balance sheet (see Note 2). Other planned major maintenance is expensed when incurred.Through 2017, SCE&G is authorized to collect $18.4$18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the yearyears ended December 31, 2011,2013 and 2012, SCE&G incurred $11.5$18.1 million and $11.1 million, respectively, for turbine maintenance. Cumulativecosts for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage.apart. SCE&G accrued $1.2$1.2 million per month from July 2008January 2010 through July 2011December 2012 for its portion of the outages in the spring of 2011 and the fall of 2009 and the spring of 2011.2012. Total costs for the 20092011 outage were $32.7$34.1 million, of which SCE&G was responsible for $21.8 million.$22.7 million. Total costs for the 20112012 outage were $34.1$32.3 million, of which SCE&G was responsible for $22.7 million.$21.5 million. In July 2011,connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began accruing $1.2to accrue $1.4 million per month for its portion of the nuclear refueling planned foroutages that are scheduled to occur through the fallspring of 2012. SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.GoodwillGoodwill$210$210 million (net of writedown of $230 million) for PSNC Energy (Gas Distribution segment) and $20$20 million for CGT (All Other segment) to be goodwill. The Company tests these goodwill amounts for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is generally a two-step quantitative process which in step one requires estimation of the fair value of the respective reporting unit and the comparison of that amount to theits carrying value of the reporting unit.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. In the first quarter of 2012, the Company will adopt accountingadopted guidance wherebyunder which it will havehas the option to first perform a qualitative assessment of impairment. Based on this qualitative ("step zero") 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 willis not be required to proceed with the two-step quantitative assessment.In evaluations of PSNC Energy, fair value iswas estimated using the assistance of an independent appraisal. In evaluations of CGT, prior to the adoption of the new guidance, estimated fair value has beenwas obtained from internal analyses.discounted cash flow and other analysis. Step zero was utilized for CGT’s evaluation as of January 1, 2013, and step one (via discounted cash flow and other analysis) was again utilized for the evaluation as of January 1, 2014. In all evaluations for the periods presented, step one or step zero, as applicable, has indicated no impairment,impairment. The estimated fair values of the reporting units are substantially in excess of their carrying values, and no impairment charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense.Nuclear DecommissioningSCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0$696.8 million, stated in 2006 dollars.2012 dollars, pursuant to an updated decommissioning cost study performed in 2012. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site wouldwill be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($($3.2 million pre-tax in each of 2011, 20102013, 2012 and 2009)2011) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.57Cash and Cash EquivalentsThe Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills and notes.Accountbills.Accounts ReceivableAccounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.InventoryTableMaterials and supplies include the average cost of ContentsAsset Management and Supply Service AgreementsPSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At December 31, 2011, suchSuch counterparties held 45%48% and 44% of PSNC Energy’s natural gas inventory at December 31, 2013 and December 31, 2012, respectively, with a carrying value of $28.7$22.8 million and $19.6 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire at various times through March 31, 2013.Income TaxesThe Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense.Regulatory Assets and Regulatory LiabilitiesThe Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See(see Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.Debt Premium, Discount and Expense, Unamortized Loss on Reacquired DebtThe Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.EnvironmentalThe Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued58when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debitsregulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.Income Statement PresentationIn its consolidated statements of income, the Company presents the activitiesrevenues and expenses of its regulated businesses and significant nonregulatedits retail natural gas marketing businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).Revenue RecognitionThe Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $169.1$183.1 million at December 31, 20112013 and $221.1$189.8 million at December 31, 2010.
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during the next annual hearing.
subsequent hearings.
See Note 2.
In Millions |
| 2011 |
| 2010 |
| 2009 |
|
Weighted Average Shares Outstanding—Basic |
| 128.8 |
| 125.7 |
| 122.1 |
|
Net effect of dilutive stock-based compensation plans and equity forward contracts |
| 1.4 |
| 0.6 |
| 0.1 |
|
Weighted Average Shares Outstanding—Diluted |
| 130.2 |
| 126.3 |
| 122.2 |
|
New Accounting Matters
Effective for the first quarter of 2012, the Company will adopt accounting guidance that revises how comprehensive income is presented in its financial statements. The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.
Effective for the first quarter of 2012, the Company will adopt accounting guidance that permits it to make a qualitative assessment about the likelihood of goodwill impairment each year. The results of such an assessment may lead the Company to determine that performing a two-step quantitative impairment test is unnecessary. The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.
| In Millions | 2013 | 2012 | 2011 | ||||||
| Weighted Average Shares Outstanding—Basic | 138.7 | 131.1 | 128.8 | ||||||
| Net effect of equity forward contracts | 0.4 | 2.2 | 1.4 | ||||||
| Weighted Average Shares Outstanding—Diluted | 139.1 | 133.3 | 130.2 | ||||||
SCE May 2013 order previously described. site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9. Year Increase Amount 2011 2.4 % $ 52.8 million 2010 2.3 % $ 47.3 million 2009 1.1 % $ 22.5 million Year Action Amount 2011 2.1 % Increase $ 8.6 million 2010 2.1 % Decrease $ 10.4 million 2009 2.5 % Increase $ 13.0 million PSNC Energy provisional basis (subject to refund) beginning January 1, 2014. December 31, Millions of dollars 2011 2010 Regulatory Assets: Accumulated deferred income taxes $ 243 $ 210 Under-collections—electric fuel adjustment clause 28 25 Environmental remediation costs 30 32 AROs and related funding 316 298 Franchise agreements 40 45 Deferred employee benefit plan costs 392 326 Planned major maintenance 6 6 Deferred losses on interest rate derivatives 154 83 Deferred pollution control costs 25 13 Other 45 23 Total Regulatory Assets $ 1,279 $ 1,061 Regulatory Liabilities: Accumulated deferred income taxes $ 23 $ 26 Asset removal costs 662 780 Storm damage reserve 32 38 Monetization of bankruptcy claim 34 37 Deferred gains on interest rate derivatives 24 26 Other 3 6 Total Regulatory Liabilities $ 778 $ 913 Accumulated deferred income tax liabilities over periods exceeding In connection with the December 2012 rate order, effective January 1, 2013, SCE&G collects and accrues The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. be recovered over periods not to exceed 24 months from date of deferral. See Rate Matters - Electric Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered lost revenue. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the collection through rates indefinitely. Millions of Dollars 2011 2010 Net unrealized losses on cash flow hedging activities, net of taxes of $50 and $22 $ (81 ) $ (36 ) Net unrealized deferred costs of employee benefit plans, net of taxes of $8 and $6 (13 ) (11 ) Total $ (94 ) $ (47 ) 2012.2. RATE AND OTHER REGULATORY MATTERSRate MattersElectric - Cost of FuelElectric&G’s&G's retail electric rates are established in part by usinginclude 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. EffectiveIn April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a twelve month period beginning with the first billing cycle of May 2010,2012.This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC approved a settlement agreement authorizingauthorized SCE&G to decreasereduce the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs. In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011. SCE&G was allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period. In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to bethe last billing cycle of April 2014 except where necessary due to extraordinary unforeseen economic or financial conditions. In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2011. On2013. Consistent with the December 2012 rate order,SCE&G did not request any adjustment to its base fuel cost component. In March 17, 2011,2013, SCE&G, ORS and the SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual baseaccepting the proposed lower environmental fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. In February 2012, SCE&G requested authorization to decrease the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2012.2013, and providing for the accrual of certain debt-related carrying costs on a portion of the under-collected balance of fuel costs. The nextSCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. A public hearing for the annual hearing to review of base rates for fuel costs ishas been scheduled for March 22, 2012.On July 15, 2010,April 3, 2014.Pursuant to a November 2013 SCPSC accounting order, the Company's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the 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. See also Note 6.Electric - Base RatesIn October 2013, SCE&G received an accounting order from the SCPSC issued an order approvingdirecting it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a 4.88%regulatory asset) 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 borrowing rate, and during 2013, $2.9 million of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these 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.In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G’s&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.7%10.25%. AmongThe SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. In February 2013, the SCPSC denied the SCEUC's petition for rehearing and the denial was not appealed.The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and had been in use since August 2010. In connection with the December 2012 order, SCE&G agreed to perform a study of alternative structures for eWNA. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC’s order (1) included implementationSCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition.In connection with the above termination of the eWNA program effective December 31, 2013, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million. Pursuant to the SCPSC accounting order granting the above relief and terminating the eWNA, for such revenue reduction was fully offset by the recognition within other60income of $8.5 million of gains realized upon the 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.SCE&G’s&G files an IRP with the SCPSC annually which evaluates future electric customers, which begangeneration needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has subsequently retired or intends to retire by 2018, subject to future developments in Augustenvironmental regulations, among other matters. One of these units was retired in 2012, and two others were retired in the fourth quarter of 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.In a July 2010 (2)order, the SCPSC provided for a $25$48.7 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits. These tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been includedwere fully amortized in utility plant but were not being depreciated.On July 15, 2010, the SCPSC issued an order approving the implementation by 2012.SCE&G of certain&G's DSM Programs including the establishment offor electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G the ORS and other intervening parties. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submitsubmits annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which went into effect as indicated below:Year Effective Amount 2013 First billing cycle of May $16.9 million 2012 First billing cycle of May $19.6 million 2011 First billing cycle of June $7.0 million Other activity related to SCE&G’s DSM Programs is as follows:In May 2013 the SCPSC ordered the deferral of one-half of the net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.In November 2013 the SCPSC approved SCE&G’s continued use of DSM programs for another six years, including approval of the rate rider mechanism and a revised portfolio of DSM programs.In January 2011,2014 SCE&G submitted its annual DSM Programs filing to the SCPSC, its annual updatewhich included, among other things, a request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on DSM Programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs. By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition. The increase became effectiveafter the first billing cycle of June 2011. In January 2012,May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the recent settlement of certain interest rate derivative instruments to offset a portion of the net lost revenues component of SCE&G submitted&G’s DSM Programs rider, and (3) apply $5 million of its storm damage reserve and a portion of the gains from the recent settlement of certain interest rate derivative instruments, currently estimated to be $5.5 million, to the SCPSC its annual update on DSM programs. Included inremaining balance of deferred net lost revenue as of April 30, 2014, deferred within regulatory assets resulting from the filing was a petition to update the rate rider to provide for the recovery of costs, lost net revenue, and the approved shared savings incentive for investing in such DSM Programs.Electric - BLRAIn January 2010,May 2011, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station. The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule sought by SCE&G that, reflected the removal of the contingency reserve andamong other matters, incorporated then identifiablethen-identifiable additional capital costs of $173.9$173.9 million (in (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011,.In November 2012, the SCPSC approved thean updated construction schedule and additional updated capital costs schedule as outlinedof $278 million (SCE&G's portion in the petition.On February 29,2007 dollars). The November 2012 SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporatesapproved additional identifiable capital costs of approximately $6&G’s&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications. That petition also includes increased capital costs ofmodifications; approximately $12$8 million (SCE&G’s&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts ofinfrastructure; and approximately $137$132 million (SCE&G’s&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filedIn addition, the order approved61revised substantial completion dates for any costs arising from the resolutionNew Units based on the March 30, 2012 issuance of the commercialCOL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims discussed in Note 1 to the consolidated financial statements (e.g., thosefor costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site).Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s&G's updated cost of debt and capital structure and on an allowed return on common equity of 11%11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:Year Increase Amount 2013 2.90% $ 67.2 million 2012 2.30% $ 52.1 million 2011 2.40% $ 52.8 million GasSCE>he 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 2013 No change 2012 2.10 % Increase $ 7.5 million 2011 2.10 % Increase $ 8.6 million SCE&G’s&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities.incurred. SCE&G’s&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month12-month rolling average. The annual PGA hearing to review SCE&G’saverage, and its gas purchasing policies and procedures was conducted in November 2011 beforepractices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2013 and 2012 resulted in the SCPSC issuedissuing an order in January 2012 finding that SCE&G’s&G's gas purchasing policies and practices during theeach review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost. The Rider D rate mechanism also allows itPSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.PSNC Energy’sEnergy's rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collectionsunder-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’sEnergy's gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.In January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in February 2012.In December 2011,October 2013, in connection with PSNC Energy’s 2011Energy's 2013 Annual Prudence Review, the NCUC determinedissued an order finding that PSNC Energy’sEnergy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 2011. On February 2, 2012,2013.During the Public Staffthird quarter of 2013, the State of North Carolina passed legislation that makes changes to statutes covering gross receipts, sales and use, excise, franchise and income taxes. In the fourth quarter, in response to this legislation, the62NCUC initiated a proceeding to investigate how it should proceed in response to the enactment of such legislation. Because the investigation was not completed before January 1, 2014, the NCUC filed a motion requestingissued an order notifying utilities that the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) fromincremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of gas. PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will haveservice would be deemed to be collected on a material effect on the Company’s results of operations, cash flows, or financial condition.In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2011. In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.Regulatory Assets and Regulatory LiabilitiesThe Company’sCompany's cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. SubstantiallyOther than unrecovered plant, substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. December 31, Millions of dollars 2013 2012 Regulatory Assets: Accumulated deferred income taxes $ 259 $ 254 Under-collections—electric fuel adjustment clause 18 66 Environmental remediation costs 41 44 AROs and related funding 368 319 Franchise agreements 31 36 Deferred employee benefit plan costs 238 460 Planned major maintenance — 6 Deferred losses on interest rate derivatives 124 151 Deferred pollution control costs 37 38 Unrecovered plant 145 20 DSM Programs 51 27 Other 48 43 Total Regulatory Assets $ 1,360 $ 1,464 Regulatory Liabilities: Accumulated deferred income taxes $ 24 $ 21 Asset removal costs 695 692 Storm damage reserve 27 27 Monetization of bankruptcy claim 29 32 Deferred gains on interest rate derivatives 181 110 Planned major maintenance 10 — Total Regulatory Liabilities $ 966 $ 882 arisingthat arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all 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 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.Under-collections-electricUnder-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods. These amounts are expected to be recovered in retail electric rates during the period January 2013 through April 2013. SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assetsCompany, and are expected to be recovered over periods of up to approximately 2326 years.63ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs.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 9590 years.Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on ana SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majorityIn connection with the December 2012 rate order, approximately $63 million of these deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates 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 14 years, although recovery periods could become longer at the election of the SCPSC.12 years.Planned major maintenance related to certain fossil fuelfossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5collects $18.4 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclearsuch equipment maintenance. Through December 31, 2012, nuclear refueling charges arewere accrued during each 18-month18-month refueling outage cycle as a component of cost of service.Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon terminationsettlement of certain interest rate swapsderivatives designated as cash flow hedges. Thesehedges and (ii) the changes in fair value and payments 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, up to approximately 30 years.Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.4 million at December 31, 2011 and are being recovered through utility rates over approximately 30 years. The remaining costs relateperiods up to Wateree Station, for which30 years.Unrecovered plant represents the Company will seek recovery in future proceedings before the SCPSC.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 allowedamortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives, or up to accrue interest onapproximately 14 years. Unamortized amounts are included in rate base and are earning a current return.DSM Programs represents deferred costs relatedand certain unrecovered lost revenue associated with SCE&G’s Demand Side Management programs. Deferred costs are currently being recovered over 5 years through a SCPSC approved rider. Unrecovered lost revenue is to Wateree Station.Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.removal ofnon-legal obligation to remove assets in the future.The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100$100 million, which can be applied to offset incremental storm damage costs in excess of $2.5$2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates. During the years ended December 31, 2011 and 2010,year. Pursuant to specific regulatory orders, SCE&G applied costs of $6.4 million and $9.5 million, respectively, to the reserve. Pursuant to SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&Ghas suspended collection of the storm damage reserve indefinitely pending future SCPSC action.The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be amortized into operating revenue through February 2024.64The SCPSC, the NCUC or the FERC havehas 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 thesesuch costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company’sCompany's results of operations, liquidity or financial position in the period the write-off would be recorded.3.COMMON EQUITYThe Company’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCANA’s junior subordinated indenture (relating to the Hybrids), SCE&G’s bond indenture (relating to the Bonds) and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on their respective common stock.With respect to hydroelectric projects, theThe Federal Power Act requires the appropriation of a portion of certain earnings therefrom.from hydroelectric projects. At December 31, 2011,2013 and 2012, approximately $58.8$63.1 million and $61.0 million of retained earnings, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.Cash dividends on SCANA’s common stock were declared during 2011, 20102013, 2012 and 20092011 at an annual rate per share of $2.03, $1.98 and $1.94, $1.90 and $1.88, respectively.The accumulated balances related to each component of accumulated other comprehensive income (loss), net of tax, were as follows:The Company recognized losses of $7.0 million, $12.3 million and $66.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2011, 2010 and 2009, respectively.Millions of Dollars Gains (Losses) on Cash Flow Hedges Deferred Employee Benefit Plans Accumulated Other Comprehensive Income (Loss) Accumulated Other Comprehensive Loss as of January 1, 2012 $ (81 ) $ (13 ) $ (94 ) Other comprehensive income (loss) 11 (3 ) 8 Accumulated Other Comprehensive Loss as of December 31, 2012 (70 ) (16 ) (86 ) Other comprehensive income 18 8 26 Accumulated Other Comprehensive Loss as of December 31, 2013 $ (52 ) $ (8 ) $ (60 ) Authorized shares of common stock were 200 million as of December 31, 20112013 and 150 million as of December 31, 2010.SCANA issued common stock valued at $97.8$100.9 million $91.1, $97.7 million and $91.1$97.8 million (when issued) during the years ended December 31, 2011, 20102013, 2012 and 2009,2011, respectively, which was satisfied using original issue shares, through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan.68In March 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.65
SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010 and entered into forward agreements for the sale of approximately 6.6 million shares. The forward agreements, after being extended by amendment dated October 26, 2011, are to be settled no later than December 31, 2012. SCANA intends to use the net proceeds to finance capital expenditures, including the construction of the New Units, and for general corporate purposes, including repayment of indebtedness incurred for such purposes.
On January 7, 2009, SCANA issued common stock valued at $102.1 million (at time of issue). Net proceeds were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.
|
|
|
| 2011 |
| 2010 |
| ||||||
Dollars in millions |
| Maturity |
| Balance |
| Rate |
| Balance |
| Rate |
| ||
Medium-Term Notes (unsecured)(a) |
| 2012 - 2021 |
| $ | 800 |
| 5.69 | % | $ | 950 |
| 6.51 | % |
Senior Notes (unsecured)(b) |
| 2034 |
| 101 |
| 6.47 | % | 106 |
| 6.47 | % | ||
First Mortgage Bonds (secured) |
| 2013 - 2041 |
| 2,790 |
| 5.89 | % | 2,560 |
| 6.03 | % | ||
Junior Subordinated Notes (unsecured)(c) |
| 2065 |
| 150 |
| 7.70 | % | 150 |
| 7.70 | % | ||
GENCO Notes (secured) |
| 2012 - 2024 |
| 247 |
| 5.86 | % | 262 |
| 5.91 | % | ||
Industrial and Pollution Control Bonds(d) |
| 2012 - 2038 |
| 194 |
| 4.48 | % | 228 |
| 4.63 | % | ||
Senior Debentures(e) |
| 2012 - 2026 |
| 353 |
| 5.92 | % | 206 |
| 6.94 | % | ||
Fair Value of Interest Rate Swaps |
|
|
| — |
|
|
| 5 |
|
|
| ||
Other |
| 2012 - 2027 |
| 31 |
|
|
| 36 |
|
|
| ||
Total debt |
|
|
| 4,666 |
|
|
| 4,503 |
|
|
| ||
Current maturities of long-term debt |
|
|
| (31 | ) |
|
| (337 | ) |
|
| ||
Unamortized discount |
|
|
| (13 | ) |
|
| (14 | ) |
|
| ||
Total long-term debt, net |
|
|
| $ | 4,622 |
|
|
| $ | 4,152 |
|
|
|
| 2013 | 2012 | |||||||||||||||
| Dollars in millions | Maturity | Balance | Rate | Balance | Rate | |||||||||||
| Medium Term Notes (unsecured) | 2020 - 2022 | $ | 800 | 5.42 | % | $ | 800 | 5.02 | % | |||||||
| Senior Notes (unsecured) (a) | 2034 | 92 | 0.94 | % | 96 | 1.01 | % | |||||||||
| First Mortgage Bonds (secured) | 2018 - 2042 | 3,540 | 5.60 | % | 3,290 | 5.66 | % | |||||||||
| Junior Subordinated Notes (unsecured) (b) | 2065 | 150 | 7.92 | % | 150 | 7.70 | % | |||||||||
| GENCO Notes (secured) | 2018 - 2024 | 233 | 5.89 | % | 240 | 5.87 | % | |||||||||
| Industrial and Pollution Control Bonds (c) | 2014 - 2038 | 158 | 3.83 | % | 161 | 4.32 | % | |||||||||
| Senior Debentures | 2020- 2026 | 350 | 5.93 | % | 350 | 5.90 | % | |||||||||
| Nuclear Fuel Financing | 2016 | 100 | 0.78 | % | — | — | ||||||||||
| Other | 2014 - 2027 | 20 | 2.73 | % | 27 | 2.39 | % | |||||||||
| Total debt | 5,443 | 5,114 | ||||||||||||||
| Current maturities of long-term debt | (54 | ) | (172 | ) | ||||||||||||
| Unamortized premium (discount) | 6 | 7 | ||||||||||||||
| Total long-term debt, net | $ | 5,395 | $ | 4,949 | ||||||||||||
(b)Variable rate notes hedged by a fixed interest rate swap.swap (fixed rate of
(c)6.47%)
2080
(e)Includes fixed rate debt hedged by a variable interest rate swap of $3.2 million in 2011 and $6.4 million in 2010.
Year |
| Millions |
| |
2012 |
| $ | 280 |
|
2013 |
| 171 |
| |
2014 |
| 52 |
| |
2015 |
| 13 |
| |
2016 |
| 12 |
| |
| Year | Millions of dollars | |||
| 2014 | $ | 54 | ||
| 2015 | 15 | |||
| 2016 | 114 | |||
| 2017 | 13 | |||
| 2018 | 722 | |||
In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.
outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2013, the Bond Ratio was
Lines of Credit and Short-Term Borrowings
|
| SCANA |
| SCE&G |
| PSNC Energy |
| ||||||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||||
Lines of Credit: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Committed long-term |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total |
| $ | 300 |
| $ | 300 |
| $ | 1,100 |
| $ | 1,100 |
| $ | 100 |
| $ | 100 |
|
LOC advances |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Weighted average interest rate |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Outstanding commercial paper (270 or fewer days) |
| $ | 131 |
| $ | 39 |
| $ | 512 |
| $ | 381 |
| $ | 10 |
| — |
| |
Weighted average interest rate |
| .63 | % | .35 | % | .56 | % | .42 | % | .57 | % | — |
| ||||||
Letters of credit supported by LOC |
| $ | 3 |
| $ | 3 |
| $ | .3 |
| $ | .3 |
| — |
| — |
| ||
Available |
| $ | 166 |
| $ | 258 |
| $ | 588 |
| $ | 719 |
| $ | 90 |
| $ | 100 |
|
| SCANA | SCE&G | PSNC Energy | ||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
| Lines of Credit: | ||||||||||||||||||||||||
| Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | ||||||||||||
| LOC advances | — | — | — | — | — | — | ||||||||||||||||||
| Weighted average interest rate | — | — | — | — | — | — | ||||||||||||||||||
| Outstanding commercial paper (270 or fewer days) | $ | 125 | $ | 142 | $ | 251 | $ | 449 | — | $ | 32 | |||||||||||||
| Weighted average interest rate | 0.39 | % | 0.58 | % | 0.27 | % | 0.42 | % | — | 0.44 | % | |||||||||||||
| Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | ||||||||||||||
| Available | $ | 172 | $ | 155 | $ | 1,149 | $ | 951 | $ | 100 | $ | 68 | ||||||||||||
credit. Such fees were not material in any period presented.
Such fees were not material in any period presented.
Total
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| |||
Current taxes: |
|
|
|
|
|
|
| |||
Federal |
| $ | 52 |
| $ | (47 | ) | $ | 63 |
|
State |
| 10 |
| 1 |
| (6 | ) | |||
Total current taxes |
| 62 |
| (46 | ) | 57 |
| |||
Deferred taxes, net: |
|
|
|
|
|
|
| |||
Federal |
| 122 |
| 223 |
| 94 |
| |||
State |
| 12 |
| 13 |
| 8 |
| |||
Total deferred taxes |
| 134 |
| 236 |
| 102 |
| |||
Investment tax credits: |
|
|
|
|
|
|
| |||
Deferred-state |
| — |
| — |
| 20 |
| |||
Amortization of amounts deferred-state |
| (25 | ) | (28 | ) | (9 | ) | |||
Amortization of amounts deferred-federal |
| (3 | ) | (3 | ) | (3 | ) | |||
Total investment tax credits |
| (28 | ) | (31 | ) | 8 |
| |||
Total income tax expense |
| $ | 168 |
| $ | 159 |
| $ | 167 |
|
| Millions of dollars | 2013 | 2012 | 2011 | |||||||||
| Current taxes: | ||||||||||||
| Federal | $ | 161 | $ | 103 | $ | 52 | ||||||
| State | 17 | 10 | 10 | |||||||||
| Total current taxes | 178 | 113 | 62 | |||||||||
| Deferred taxes, net: | ||||||||||||
| Federal | 39 | 72 | 122 | |||||||||
| State | 10 | 14 | 12 | |||||||||
| Total deferred taxes | 49 | 86 | 134 | |||||||||
| Investment tax credits: | ||||||||||||
| Amortization of amounts deferred-state | (1 | ) | (14 | ) | (25 | ) | ||||||
| Amortization of amounts deferred-federal | (3 | ) | (3 | ) | (3 | ) | ||||||
| Total investment tax credits | (4 | ) | (17 | ) | (28 | ) | ||||||
| Total income tax expense | $ | 223 | $ | 182 | $ | 168 | ||||||
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:
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| |||
Income |
| $ | 387 |
| $ | 376 |
| $ | 348 |
|
Income tax expense |
| 168 |
| 159 |
| 167 |
| |||
Preferred stock dividends |
| — |
| — |
| 9 |
| |||
Total pre-tax income |
| $ | 555 |
| $ | 535 |
| $ | 524 |
|
Income taxes on above at statutory federal income tax rate |
| $ | 194 |
| $ | 187 |
| $ | 183 |
|
Increases (decreases) attributed to: |
|
|
|
|
|
|
| |||
State income taxes (less federal income tax effect) |
| 15 |
| 9 |
| 14 |
| |||
Amortization of state investment tax credits (less federal income tax effect) |
| (16 | ) | (18 | ) | (6 | ) | |||
Allowance for equity funds used during construction |
| (5 | ) | (8 | ) | (10 | ) | |||
Deductible dividends—Stock Purchase Savings Plan |
| (9 | ) | (9 | ) | (8 | ) | |||
Amortization of federal investment tax credits |
| (3 | ) | (3 | ) | (3 | ) | |||
Domestic production activities deduction |
| (6 | ) | — |
| (4 | ) | |||
Other differences, net |
| (2 | ) | 1 |
| 1 |
| |||
Total income tax expense |
| $ | 168 |
| $ | 159 |
| $ | 167 |
|
| Millions of dollars | 2013 | 2012 | 2011 | |||||||||
| Net income | $ | 471 | $ | 420 | $ | 387 | ||||||
| Income tax expense | 223 | 182 | 168 | |||||||||
| Total pre-tax income | $ | 694 | $ | 602 | $ | 555 | ||||||
| Income taxes on above at statutory federal income tax rate | $ | 243 | $ | 211 | $ | 194 | ||||||
| Increases (decreases) attributed to: | ||||||||||||
| State income taxes (less federal income tax effect) | 22 | 19 | 15 | |||||||||
| State investment tax credits (less federal income tax effect) | (5 | ) | (13 | ) | (16 | ) | ||||||
| Allowance for equity funds used during construction | (9 | ) | (8 | ) | (5 | ) | ||||||
| Deductible dividends—Stock Purchase Savings Plan | (10 | ) | (9 | ) | (9 | ) | ||||||
| Amortization of federal investment tax credits | (3 | ) | (3 | ) | (3 | ) | ||||||
| Section 45 tax credits | (5 | ) | (5 | ) | (2 | ) | ||||||
| Domestic production activities deduction | (11 | ) | (9 | ) | (6 | ) | ||||||
| Other differences, net | 1 | (1 | ) | — | ||||||||
| Total income tax expense | $ | 223 | $ | 182 | $ | 168 | ||||||
Millions of dollars |
| 2011 |
| 2010 |
| ||
Deferred tax assets: |
|
|
|
|
| ||
Nondeductible reserves |
| $ | 99 |
| $ | 103 |
|
Nuclear decommissioning |
| 47 |
| 45 |
| ||
Financial instruments |
| 50 |
| 22 |
| ||
Unamortized investment tax credits |
| 29 |
| 41 |
| ||
Deferred compensation |
| 23 |
| 25 |
| ||
Unbilled revenue |
| 19 |
| 19 |
| ||
Monetization of bankruptcy claim |
| 13 |
| 14 |
| ||
Other |
| 15 |
| 11 |
| ||
Total deferred tax assets |
| $ | 295 |
| $ | 280 |
|
Deferred tax liabilities: |
|
|
|
|
| ||
Property, plant and equipment |
| $ | 1,561 |
| $ | 1,418 |
|
Pension plan income |
| 1 |
| 23 |
| ||
Deferred employee benefit plan costs |
| 128 |
| 106 |
| ||
Deferred fuel costs |
| 47 |
| 42 |
| ||
Other |
| 65 |
| 61 |
| ||
Total deferred tax liabilities |
| 1,802 |
| 1,650 |
| ||
Net deferred tax liability |
| $ | 1,507 |
| $ | 1,370 |
|
| Millions of dollars | 2013 | 2012 | ||||||
| Deferred tax assets: | ||||||||
| Nondeductible accruals | $ | 84 | $ | 143 | ||||
| Asset retirement obligation, including nuclear decommissioning | 220 | 214 | ||||||
| Financial instruments | 32 | 43 | ||||||
| Unamortized investment tax credits | 19 | 22 | ||||||
| Regulatory liability, net gain on interest rate derivative contracts settlement | 27 | — | ||||||
| Unbilled revenue | — | 14 | ||||||
| Monetization of bankruptcy claim | 11 | 12 | ||||||
| Other | 13 | 15 | ||||||
| Total deferred tax assets | 406 | 463 | ||||||
| Deferred tax liabilities: | ||||||||
| Property, plant and equipment | $ | 1,765 | $ | 1,718 | ||||
| Deferred employee benefit plan costs | 63 | 148 | ||||||
| Regulatory asset-asset retirement obligation | 121 | 113 | ||||||
| Deferred fuel costs | 25 | 48 | ||||||
| Regulatory asset, unrecovered plant | 55 | 7 | ||||||
| Other | 84 | 71 | ||||||
| Total deferred tax liabilities | 2,113 | 2,105 | ||||||
| Net deferred tax liability | $ | 1,707 | $ | 1,642 | ||||
In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, the Company revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.
Changes to Unrecognized Tax Benefits
Millions of dollars |
| 2011 |
| 2010 |
| ||
Unrecognized tax benefits, January 1 |
| $ | 36 |
| — |
| |
Gross increases—tax positions in prior period |
| 5 |
| — |
| ||
Gross decreases—tax positions in prior period |
| (8 | ) | — |
| ||
Gross increases—current period tax positions |
| 5 |
| $ | 36 |
| |
Settlements |
| — |
| — |
| ||
Lapse of statute of limitations |
| — |
| — |
| ||
Unrecognized tax benefits, December 31 |
| $ | 38 |
| $ | 36 |
|
| Millions of dollars | 2013 | 2012 | 2011 | |||||||||
| Unrecognized tax benefits, January 1 | — | $ | 38 | $ | 36 | |||||||
| Gross increases—uncertain tax positions in prior period | — | — | 5 | |||||||||
| Gross decreases—uncertain tax positions in prior period | — | (38 | ) | (8 | ) | |||||||
| Gross increases—current period uncertain tax positions | $ | 3 | — | 5 | ||||||||
| Settlements | — | — | — | |||||||||
| Lapse of statute of limitations | — | — | — | |||||||||
| Unrecognized tax benefits, December 31 | $ | 3 | $ | — | $ | 38 | ||||||
the Company’s tax positions have occurred through December 31, 2013.
position.
The Company’s regulated gas operations (SCE&G and
losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.
The unrealized
Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.
The Company uses swaps to synthetically convert fixed rate debt to variable rate debt. These swaps are designated as fair value hedges. Periodic payments to or receipts from swap counterparties are recorded within interest expense and are classified as an operating activityIn cases in which the condensed consolidated statements of cash flows. In addition, gains on certain swaps that were terminated prior to maturity of the underlying debt instruments are being amortized to interest expense over the life of the debt they hedged.
The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodichedges, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.
expense.
flow statement purposes.
|
| Commodity and Other Energy |
| ||||||
Hedge designation |
| Gas |
| Retail Gas |
| Energy |
| Total |
|
As of December 31, 2011 |
|
|
|
|
|
|
|
|
|
Cash flow |
| — |
| 6,566,000 |
| 29,861,763 |
| 36,427,763 |
|
Not designated(a) |
| 9,080,000 |
| — |
| 31,943,563 |
| 41,023,563 |
|
Total(a) |
| 9,080,000 |
| 6,566,000 |
| 61,805,326 |
| 77,451,326 |
|
As of December 31, 2010 |
|
|
|
|
|
|
|
|
|
Cash flow |
| — |
| 5,715,000 |
| 17,190,351 |
| 22,905,351 |
|
Not designated(b) |
| 10,677,000 |
| — |
| 20,588,581 |
| 31,265,581 |
|
Total(b) |
| 10,677,000 |
| 5,715,000 |
| 37,778,932 |
| 54,170,932 |
|
Commodity and Other Energy Management Contracts (in MMBTU) | ||||||||||||
| Hedge designation | Gas Distribution | Retail Gas Marketing | Energy Marketing | Total | ||||||||
| As of December 31, 2013 | ||||||||||||
| Commodity | 6,070,000 | 6,726,000 | 2,560,000 | 15,356,000 | ||||||||
| Energy Management (a) | — | — | 27,359,958 | 27,359,958 | ||||||||
| Total (a) | 6,070,000 | 6,726,000 | 29,919,958 | 42,715,958 | ||||||||
| As of December 31, 2012 | ||||||||||||
| Commodity | 5,170,000 | 6,490,000 | 4,877,000 | 16,537,000 | ||||||||
| Energy Management (b) | — | — | 31,763,275 | 31,763,275 | ||||||||
| Total (b) | 5,170,000 | 6,490,000 | 36,640,275 | 48,300,275 | ||||||||
The Company was party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $253.2 million and $556.4 million at December 31, 2011 and 2010, respectively, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $822.6$128.8 million at December 31, 2013, and $1.1 billion at December 31, 2012. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion and $0.0 million at December 31, 2013 and 2012, respectively.
|
| Fair Values of Derivative Instruments |
| ||||||||
|
| Asset Derivatives |
| Liability Derivatives |
| ||||||
Millions of |
| Balance Sheet |
| Fair |
| Balance Sheet |
| Fair |
| ||
As of December 31, 2011 |
|
|
|
|
|
|
|
|
| ||
Derivatives designated as hedging instruments |
|
|
|
|
|
|
|
|
| ||
Interest rate contracts |
| Prepayments and other |
| $ | 2 |
| Other current liabilities |
| $ | 55 |
|
|
|
|
|
|
| Other deferred credits and other liabilities |
| 103 |
| ||
Commodity contracts |
| Other current liabilities |
| 1 |
| Prepayments and other |
| 1 |
| ||
|
|
|
| $ | 3 |
| Other current liabilities |
| 10 |
| |
|
|
|
|
|
| Other deferred credits and other liabilities |
| 3 |
| ||
Total |
|
|
|
|
|
|
| $ | 172 |
| |
|
|
|
|
|
|
|
|
|
| ||
As of December 31, 2010 |
|
|
|
|
|
|
|
|
| ||
Derivatives designated as hedging instruments |
|
|
|
|
|
|
|
|
| ||
Interest rate contracts |
| Prepayments and other |
| $ | 1 |
| Other current liabilities |
| $ | 57 |
|
|
| Other deferred debits and other assets |
| 7 |
| Other deferred credits and other liabilities |
| 25 |
| ||
Commodity contracts |
| Other current liabilities |
| 1 |
| Other current liabilities |
| 5 |
| ||
|
|
|
|
|
| Other deferred credits and other liabilities |
| 2 |
| ||
Total |
|
|
| $ | 9 |
|
|
| $ | 89 |
|
|
|
|
|
|
|
|
|
|
| ||
As of December 31, 2011 |
|
|
|
|
|
|
|
|
| ||
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
| ||
Energy management contracts |
| Prepayments and other |
| $ | 17 |
| Prepayments and other |
| $ | 3 |
|
|
| Other deferred debits and other assets |
| 10 |
| Other current liabilities |
| 13 |
| ||
|
|
|
|
|
| Other deferred credits and other liabilities |
| 9 |
| ||
Total |
|
|
| $ | 27 |
|
|
| $ | 25 |
|
|
|
|
|
|
|
|
|
|
| ||
As of December 31, 2010 |
|
|
|
|
|
|
|
|
| ||
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
| ||
Commodity contracts |
| Prepayments and other |
| $ | 3 |
|
|
|
|
| |
Energy management contracts |
| Prepayments and other |
| 7 |
| Prepayments and other |
| $ | 1 |
| |
|
| Other deferred debits and other assets |
| 2 |
| Other current liabilities |
| 6 |
| ||
|
|
|
|
|
| Other deferred credits and other liabilities |
| 2 |
| ||
Total |
|
|
| $ | 12 |
|
|
| $ | 9 |
|
(c)Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses. In the Company’s consolidated balance sheet, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.
| Fair Values of Derivative Instruments | ||||||||||||
| Asset Derivatives | Liability Derivatives | |||||||||||
| Millions of dollars | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||
| As of December 31, 2013 | ||||||||||||
| Derivatives designated as hedging instruments | ||||||||||||
| Interest rate contracts | Other current liabilities | $ | 5 | |||||||||
| Other deferred credits and other liabilities | 14 | |||||||||||
| Commodity contracts | Prepayments and other | $ | 2 | |||||||||
| Total | $ | 2 | $ | 19 | ||||||||
| Derivatives not designated as hedging instruments | ||||||||||||
| Interest rate contracts | Prepayments and other | $ | 13 | Other current liabilities | $ | 1 | ||||||
| Other deferred debits and other assets | 19 | |||||||||||
| Commodity contracts | Prepayments and other | 2 | ||||||||||
| Energy management contracts | Prepayments and other | 4 | Other current liabilities | 4 | ||||||||
| Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | |||||||||
| Total | $ | 42 | $ | 9 | ||||||||
| As of December 31, 2012 | ||||||||||||
| Derivatives designated as hedging instruments | ||||||||||||
| Interest rate contracts | Prepayments and other | $ | 42 | Other current liabilities | $ | 70 | ||||||
| Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 36 | |||||||||
| Commodity contracts | Prepayments and other | 1 | Other current liabilities | 4 | ||||||||
| Total | $ | 74 | $ | 110 | ||||||||
| Derivatives not designated as hedging instruments | ||||||||||||
| Commodity contracts | Prepayments and other | $ | 1 | |||||||||
| Energy management contracts | Prepayments and other | 7 | Prepayments and other | $ | 1 | |||||||
| Other deferred debits and other assets | 6 | Other current liabilities | 6 | |||||||||
| Other deferred debits and other assets | 6 | |||||||||||
| Total | $ | 14 | $ | 13 | ||||||||
The effect of derivative instruments on the statementconsolidated statements of income is as follows:
were not significant during any period presented.
Derivatives in Cash Flow Hedging Relationships |
| Gain or (Loss) |
| Gain or (Loss) Reclassified from |
| ||||
Millions of dollars |
| (Effective Portion) |
| Location |
| Amount |
| ||
Year Ended December 31, 2011 |
|
|
|
|
|
|
| ||
Interest rate contracts |
| $ | (76 | ) | Interest expense |
| $ | (3 | ) |
Year Ended December 31, 2010 |
|
|
|
|
|
|
| ||
Interest rate contracts |
| $ | (36 | ) | Interest expense |
| $ | (2 | ) |
Year Ended December 31, 2009 |
|
|
|
|
|
|
| ||
Interest rate contracts |
| $ | 42 |
| Interest expense |
| $ | (3 | ) |
Derivatives in Cash Flow Hedging Relationships |
| Gain or (Loss) |
| Gain or (Loss) Reclassified from |
| ||||
Millions of dollars |
| (Effective Portion) |
| Location |
| Amount |
| ||
Year Ended December 31, 2011 |
|
|
|
|
|
|
| ||
Interest rate contracts |
| $ | (42 | ) | Interest expense |
| $ | (4 | ) |
Commodity contracts |
| (16 | ) | Gas purchased for resale |
| (9 | ) | ||
Total |
| $ | (58 | ) |
|
| $ | (13 | ) |
Year Ended December 31, 2010 |
|
|
|
|
|
|
| ||
Interest rate contracts |
| $ | (24 | ) | Interest expense |
| $ | (4 | ) |
Commodity contracts |
| (12 | ) | Gas purchased for resale |
| (13 | ) | ||
Total |
| $ | (36 | ) |
|
| $ | (17 | ) |
Year Ended December 31, 2009 |
|
|
|
|
|
|
| ||
Interest rate contracts |
| $ | 9 |
| Interest expense |
| $ | (3 | ) |
Commodity contracts |
| (39 | ) | Gas purchased for resale |
| (67 | ) | ||
Total |
| $ | (30 | ) |
|
| $ | (70 | ) |
Gain or (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, 2013 | ||||||||||
| Interest rate contracts | $ | 106 | Interest expense | $ | (3 | ) | ||||
| Year Ended December 31, 2012 | ||||||||||
| Interest rate contracts | $ | 84 | Interest expense | $ | (3 | ) | ||||
| Year Ended December 31, 2011 | ||||||||||
| Interest rate contracts | $ | (76 | ) | Interest expense | $ | (3 | ) | |||
Gain or (Loss) Recognized in OCI, net of tax | Loss Reclassified from Accumulated OCI into Income, net of tax (Effective Portion) | |||||||||
| Millions of dollars | (Effective Portion) | Location | Amount | |||||||
| Year Ended December 31, 2013 | ||||||||||
| Interest rate contracts | $ | 5 | Interest expense | $ | (8 | ) | ||||
| Commodity contracts | 2 | Gas purchased for resale | (3 | ) | ||||||
| Total | $ | 7 | $ | (11 | ) | |||||
| Year Ended December 31, 2012 | ||||||||||
| Interest rate contracts | $ | (4 | ) | Interest expense | $ | (6 | ) | |||
| Commodity contracts | (4 | ) | Gas purchased for resale | (13 | ) | |||||
| Total | $ | (8 | ) | $ | (19 | ) | ||||
| Year Ended December 31, 2011 | ||||||||||
| Interest rate contracts | $ | (42 | ) | Interest expense | $ | (4 | ) | |||
| Commodity contracts | (16 | ) | Gas purchased for resale | (9 | ) | |||||
| Total | $ | (58 | ) | $ | (13 | ) | ||||
Derivatives Not Designated as Hedging Instruments |
| Gain or (Loss) Recognized in Income |
| |||
Millions of dollars |
| Location |
| Amount |
| |
Year Ended December 31, 2011 |
|
|
|
|
| |
Commodity contracts |
| Gas purchased for resale |
| $ | (2 | ) |
Year Ended December 31, 2010 |
|
|
|
|
| |
Commodity contracts |
| Gas purchased for resale |
| (3 | ) | |
Year Ended December 31, 2009 |
|
|
|
|
| |
Commodity contracts |
| Gas purchased for resale |
| (16 | ) | |
| Loss Recognized in Income | Year Ended December 31, | ||||||||||||
| Millions of dollars | Location | 2013 | 2012 | 2011 | |||||||||
| Commodity contracts | Gas purchased for resale | — | $ | (1 | ) | $ | (2 | ) | |||||
Gain or (Loss) Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||
| Millions of dollars | Location | Amount | ||||||||
| Year Ended December 31, 2013 | ||||||||||
| Interest rate contracts | $ | 39 | Other income | $ | 50 | |||||
| Year Ended December 31, 2012 | ||||||||||
| Interest rate contracts | $ | — | $ | — | ||||||
| Year Ended December 31, 2011 | ||||||||||
| Interest rate contracts | $ | — | $ | — | ||||||
$50 million offset revenue reductions as previously described herein and in Note 2.
| Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||
| Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | ||||||||||||||||
| As of December 31, 2013 | ||||||||||||||||||||||
| Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | |||||||||||
| Commodity | 4 | — | 4 | — | — | 4 | ||||||||||||||||
| Energy Management | 8 | — | 8 | — | — | 8 | ||||||||||||||||
| Total | $ | 44 | — | $ | 44 | $ | (1 | ) | — | $ | 43 | |||||||||||
| Balance sheet location | Prepayments and other | $ | 21 | |||||||||||||||||||
| Other deferred debits and other assets | 23 | |||||||||||||||||||||
| Total | $ | 44 | ||||||||||||||||||||
| As of December 31, 2012 | ||||||||||||||||||||||
| Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | |||||||||||
| Commodity | 2 | — | 2 | — | — | 2 | ||||||||||||||||
| Energy Management | 13 | $ | (1 | ) | 12 | — | — | 12 | ||||||||||||||
| Total | $ | 88 | $ | (1 | ) | $ | 87 | $ | (17 | ) | — | $ | 70 | |||||||||
| Balance sheet location | Prepayments and other | $ | 50 | |||||||||||||||||||
| Other deferred debits and other assets | 37 | |||||||||||||||||||||
| Total | $ | 87 | ||||||||||||||||||||
| Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||
| Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | ||||||||||||||||
| As of December 31, 2013 | ||||||||||||||||||||||
| Interest rate | $ | 20 | — | $ | 20 | $ | (1 | ) | $ | 19 | — | |||||||||||
| Energy Management | 8 | — | 8 | — | 6 | $ | 2 | |||||||||||||||
| Total | $ | 28 | — | $ | 28 | $ | (1 | ) | $ | 25 | $ | 2 | ||||||||||
| Balance sheet location | Other current liabilities | $ | 10 | |||||||||||||||||||
| Other deferred credits and other liabilities | 18 | |||||||||||||||||||||
| Total | $ | 28 | ||||||||||||||||||||
| Gross Amounts Not Offset in the Statement of Financial Position | |||||||||||||||||||||||
| Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | |||||||||||||||||
| As of December 31, 2012 | |||||||||||||||||||||||
| Interest rate | $ | 106 | — | $ | 106 | $ | (17 | ) | $ | 67 | $ | 22 | |||||||||||
| Commodity | 4 | — | 4 | — | — | 4 | |||||||||||||||||
| Energy Management | 13 | $ | (1 | ) | 12 | — | 11 | 1 | |||||||||||||||
| Total | $ | 123 | $ | (1 | ) | $ | 122 | $ | (17 | ) | $ | 78 | $ | 27 | |||||||||
| Balance sheet location | Other current liabilities | $ | 80 | ||||||||||||||||||||
| Other deferred credits and other liabilities | 42 | ||||||||||||||||||||||
| Total | $ | 122 | |||||||||||||||||||||
|
| Fair Value Measurements Using |
| ||||
Millions of dollars |
| Quoted Prices in Active |
| Significant Other |
| ||
As of December 31, 2011 |
|
|
|
|
| ||
Assets-Available for sale securities |
| $ | 3 |
| — |
| |
Interest rate contracts |
| — |
| $ | 2 |
| |
Commodity contracts |
| — |
| 1 |
| ||
Energy management contracts |
| — |
| 27 |
| ||
Liabilities-Interest rate contracts |
| — |
| 158 |
| ||
Commodity contracts |
| 1 |
| 13 |
| ||
Energy management contracts |
| — |
| 26 |
| ||
As of December 31, 2010 |
|
|
|
|
| ||
Assets-Available for sale securities |
| $ | 3 |
| — |
| |
Interest rate contracts |
| — |
| $ | 8 |
| |
Commodity contracts |
| 2 |
| 2 |
| ||
Energy management contracts |
| — |
| 9 |
| ||
Liabilities-Interest rate contracts |
| — |
| 82 |
| ||
Commodity contracts |
| 1 |
| 6 |
| ||
Energy management contracts |
| — |
| 11 |
| ||
| As of December 31, 2013 | As of December 31, 2012 | ||||||||||||||
| Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||
| Assets: | |||||||||||||||
| Available for sale securities | $ | 9 | — | $ | 6 | — | |||||||||
| Interest rate contracts | — | $ | 32 | — | $ | 73 | |||||||||
| Commodity contracts | 2 | 2 | 1 | 1 | |||||||||||
| Energy management contracts | 1 | 7 | — | 13 | |||||||||||
| Liabilities: | |||||||||||||||
| Interest rate contracts | — | 20 | — | 106 | |||||||||||
| Commodity contracts | — | — | — | 4 | |||||||||||
| Energy management contracts | — | 12 | 1 | 15 | |||||||||||
|
| December 31, 2011 |
| December 31, 2010 |
| ||||||||
Millions of dollars |
| Carrying |
| Estimated |
| Carrying |
| Estimated |
| ||||
Long-term debt |
| $ | 4,653.0 |
| $ | 5,479.2 |
| $ | 4,488.3 |
| $ | 4,840.5 |
|
| As of December 31, 2013 | As of December 31, 2012 | |||||||||||||||
| Millions of dollars | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
| Long-term debt | $ | 5,449.3 | $ | 5,916.3 | $ | 5,121.0 | $ | 6,115.0 | ||||||||
76
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.
|
| Pension |
| Other |
| ||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Benefit obligation, January 1 |
| $ | 811.8 |
| $ | 789.4 |
| $ | 213.5 |
| $ | 210.4 |
|
Service cost |
| 18.3 |
| 17.9 |
| 4.3 |
| 4.2 |
| ||||
Interest cost |
| 43.5 |
| 44.0 |
| 12.2 |
| 11.9 |
| ||||
Plan participants’ contributions |
| — |
| — |
| 3.2 |
| 3.1 |
| ||||
Actuarial (gain) loss |
| 0.4 |
| (1.1 | ) | 7.2 |
| (1.6 | ) | ||||
Benefits paid |
| (43.9 | ) | (38.4 | ) | (14.3 | ) | (14.5 | ) | ||||
Benefit obligation, December 31 |
| $ | 830.1 |
| $ | 811.8 |
| $ | 226.1 |
| $ | 213.5 |
|
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Benefit obligation, January 1 | $ | 931.6 | $ | 830.1 | $ | 265.3 | $ | 226.1 | ||||||||
| Service cost | 21.8 | 19.6 | 5.9 | 4.8 | ||||||||||||
| Interest cost | 38.5 | 43.0 | 11.1 | 11.9 | ||||||||||||
| Plan participants’ contributions | — | — | 2.6 | 2.9 | ||||||||||||
| Actuarial (gain) loss | (83.4 | ) | 96.5 | (35.1 | ) | 33.4 | ||||||||||
| Benefits paid | (60.0 | ) | (57.6 | ) | (11.8 | ) | (13.8 | ) | ||||||||
| Curtailment | (25.5 | ) | — | — | — | |||||||||||
| Benefit obligation, December 31 | $ | 823.0 | $ | 931.6 | $ | 238.0 | $ | 265.3 | ||||||||
|
| Pension |
| Other |
| ||||
|
| 2011 |
| 2010 |
| 2011 |
| 2010 |
|
Annual discount rate used to determine benefit obligation |
| 5.25 | % | 5.56 | % | 5.35 | % | 5.72 | % |
Assumed annual rate of future salary increases for projected benefit obligation |
| 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % |
An 8.2%
| Pension Benefits | Other Postretirement Benefits | ||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||
| Annual discount rate used to determine benefit obligation | 5.03 | % | 4.10 | % | 5.19 | % | 4.19 | % | |||
| Assumed annual rate of future salary increases for projected benefit obligation | 3.00 | % | 3.75 | % | 3.75 | % | 3.75 | % | |||
Funded Status
Millions of Dollars |
| Pension |
| Other |
| ||||||||
December 31, |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Fair value of plan assets |
| $ | 755.0 |
| $ | 817.2 |
| — |
| — |
| ||
Benefit obligations |
| 830.1 |
| 811.8 |
| $ | 226.1 |
| $ | 213.5 |
| ||
Funded status - asset (liability) |
| $ | (75.1 | ) | $ | 5.4 |
| $ | (226.1 | ) | $ | (213.5 | ) |
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Fair value of plan assets | $ | 870.0 | $ | 799.1 | — | — | ||||||||||
| Benefit obligation | 823.0 | 931.6 | $ | 238.0 | $ | 265.3 | ||||||||||
| Funded status | $ | 47.0 | $ | (132.5 | ) | $ | (238.0 | ) | $ | (265.3 | ) | |||||
Millions of Dollars |
| Pension |
| Other |
| ||||||||
December 31, |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Noncurrent asset |
| — |
| $ | 5.4 |
| — |
| — |
| |||
Current liability |
| — |
| — |
| $ | (10.5 | ) | $ | (11.4 | ) | ||
Noncurrent liability |
| $ | (75.1 | ) | — |
| (215.6 | ) | (202.1 | ) | |||
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Current liability | — | — | $ | (11.5 | ) | $ | (11.0 | ) | ||||||||
| Noncurrent asset | $ | 47.0 | — | — | — | |||||||||||
| Noncurrent liability | — | $ | (132.5 | ) | (226.5 | ) | (254.3 | ) | ||||||||
Millions of Dollars |
| Pension |
| Other |
| ||||||||
December 31, |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Net actuarial loss |
| $ | 9.6 |
| $ | 7.1 |
| $ | 1.7 |
| $ | 1.3 |
|
Prior service cost |
| 1.2 |
| 1.4 |
| 0.1 |
| 0.2 |
| ||||
Transition obligation |
| — |
| — |
| 0.2 |
| 0.3 |
| ||||
Total |
| $ | 10.8 |
| $ | 8.5 |
| $ | 2.0 |
| $ | 1.8 |
|
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net actuarial loss | $ | 5.2 | $ | 10.7 | $ | 1.7 | $ | 3.7 | ||||||||
| Prior service cost | 0.5 | 1.0 | 0.1 | 0.1 | ||||||||||||
| Transition obligation | — | — | — | 0.1 | ||||||||||||
| Total | $ | 5.7 | $ | 11.7 | $ | 1.8 | $ | 3.9 | ||||||||
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net actuarial loss | $ | 124.8 | $ | 297.0 | $ | 24.4 | $ | 57.0 | ||||||||
| Prior service cost | 12.8 | 26.9 | 0.9 | 1.5 | ||||||||||||
| Transition obligation | — | — | — | 0.2 | ||||||||||||
| Total | $ | 137.6 | $ | 323.9 | $ | 25.3 | $ | 58.7 | ||||||||
|
| Pension Benefits |
| ||||
Millions of dollars |
| 2011 |
| 2010 |
| ||
Fair value of plan assets, January 1 |
| $ | 817.2 |
| $ | 758.9 |
|
Actual return on plan assets |
| (18.3 | ) | 96.7 |
| ||
Benefits paid |
| (43.9 | ) | (38.4 | ) | ||
Fair value of plan assets, December 31 |
| $ | 755.0 |
| $ | 817.2 |
|
| Pension Benefits | ||||||||
| Millions of dollars | 2013 | 2012 | ||||||
| Fair value of plan assets, January 1 | $ | 799.1 | $ | 755.0 | ||||
| Actual return on plan assets | 130.9 | 101.7 | ||||||
| Benefits paid | (60.0 | ) | (57.6 | ) | ||||
| Fair value of plan assets, December 31 | $ | 870.0 | $ | 799.1 | ||||
engaging in speculative trading are also prohibited.
|
| Percentage of Plan Assets |
| ||||
|
| Target |
| At |
| ||
Asset Category |
| 2012 |
| 2011 |
| 2010 |
|
Equity Securities |
| 65 | % | 65 | % | 68 | % |
Debt Securities |
| 35 | % | 35 | % | 32 | % |
| Percentage of Plan Assets | |||||||||
Target Allocation | At December 31, | ||||||||
| Asset Category | 2014 | 2013 | 2012 | ||||||
| Equity Securities | 58 | % | 59 | % | 66 | % | |||
| Fixed Income | 33 | % | 32 | % | 25 | % | |||
| Hedge Funds | 9 | % | 9 | % | 9 | % | |||
Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment policy adopted for 2014.
|
|
|
| Fair Value Measurements at Reporting |
| ||||||||
Millions of dollars |
| Total |
| Quoted Market Prices |
| Significant |
| Significant |
| ||||
December 31, 2011 |
|
|
|
|
|
|
|
|
| ||||
Common stock |
| $ | 324 |
| $ | 324 |
|
|
|
|
| ||
Preferred stock |
| 1 |
| 1 |
|
|
|
|
| ||||
Mutual funds |
| 183 |
| 20 |
| $ | 163 |
|
|
| |||
Short-term investment vehicles |
| 23 |
|
|
| 23 |
|
|
| ||||
Government agency securities |
| 32 |
|
|
| 32 |
|
|
| ||||
Corporate debt securities |
| 51 |
|
|
| 51 |
|
|
| ||||
Loans secured by mortgages |
| 12 |
|
|
| 12 |
|
|
| ||||
Municipals |
| 4 |
|
|
| 4 |
|
|
| ||||
Common collective trusts |
| 37 |
|
|
| 37 |
|
|
| ||||
Limited partnerships |
| 23 |
|
|
| 23 |
|
|
| ||||
Multi-strategy hedge funds |
| 65 |
|
|
|
|
| $ | 65 |
| |||
|
| $ | 755 |
| $ | 345 |
| $ | 345 |
| $ | 65 |
|
|
|
|
|
|
|
|
|
|
| ||||
December 31, 2010 |
|
|
|
|
|
|
|
|
| ||||
Common stock |
| $ | 363 |
| $ | 363 |
|
|
|
|
| ||
Mutual funds |
| 206 |
| 25 |
| $ | 181 |
|
|
| |||
Short-term investment vehicles |
| 18 |
|
|
| 18 |
|
|
| ||||
Government agency securities |
| 51 |
|
|
| 51 |
|
|
| ||||
Corporate debt securities |
| 51 |
|
|
| 51 |
|
|
| ||||
Loans secured by mortgages |
| 9 |
|
|
| 9 |
|
|
| ||||
Municipals |
| 3 |
|
|
| 3 |
|
|
| ||||
Common collective trusts |
| 45 |
|
|
| 45 |
|
|
| ||||
Limited partnerships |
| 26 |
| 1 |
| 25 |
|
|
| ||||
Multi-strategy hedge funds |
| 45 |
|
|
|
|
| $ | 45 |
| |||
|
| $ | 817 |
| $ | 389 |
| $ | 383 |
| $ | 45 |
|
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||||||||||||||||||
| Millions of dollars | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| December 31, 2013 | December 31, 2012 | |||||||||||||||||||||||||||||||
| Common stock | $ | 332 | $ | 332 | $ | 319 | $ | 319 | ||||||||||||||||||||||||
| Preferred stock | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||||||
| Mutual funds | 305 | 20 | $ | 285 | 246 | 12 | $ | 234 | ||||||||||||||||||||||||
| Short-term investment vehicles | 19 | 19 | 20 | 20 | ||||||||||||||||||||||||||||
| US Treasury securities | 33 | 33 | 42 | 42 | ||||||||||||||||||||||||||||
| Corporate debt securities | 53 | 53 | 56 | 56 | ||||||||||||||||||||||||||||
| Loans secured by mortgages | 12 | 12 | 11 | 11 | ||||||||||||||||||||||||||||
| Municipals | 4 | 4 | 4 | 4 | ||||||||||||||||||||||||||||
| Limited partnerships | 35 | 1 | 34 | 30 | 1 | 29 | ||||||||||||||||||||||||||
| Multi‑strategy hedge funds | 76 | $ | 76 | 70 | $ | 70 | ||||||||||||||||||||||||||
| $ | 870 | $ | 354 | $ | 440 | $ | 76 | $ | 799 | $ | 333 | $ | 396 | $ | 70 | |||||||||||||||||
fair value amounts into or out of Level 1, 2 or 3 during 2013 or 2012.
|
| Fair Value |
| ||||
Millions of dollars |
| 2011 |
| 2010 |
| ||
Beginning Balance |
| $ | 45 |
| $ | 14 |
|
Unrealized gains (losses) included in changes in net assets |
| (1 | ) | 2 |
| ||
Purchases, issuances, and settlements |
| 21 |
| 29 |
| ||
Transfers in or out of Level 3 |
| — |
| — |
| ||
Ending Balance |
| $ | 65 |
| $ | 45 |
|
Fair Value Measurements Level 3 | ||||||||
| Millions of dollars | 2013 | 2012 | ||||||
| Beginning Balance | $ | 70 | $ | 65 | ||||
| Unrealized gains included in changes in net assets | 6 | 5 | ||||||
| Purchases, issuances, and settlements | — | — | ||||||
| Ending Balance | $ | 76 | $ | 70 | ||||
|
|
|
| Other Postretirement Benefits* |
| |||||
Millions of dollars |
| Pension |
| Excluding Medicare |
| Including Medicare |
| |||
2012 |
| $ | 73.4 |
| $ | 11.1 |
| $ | 10.8 |
|
2013 |
| 66.8 |
| 11.8 |
| 11.5 |
| |||
2014 |
| 61.8 |
| 12.6 |
| 12.3 |
| |||
2015 |
| 63.3 |
| 13.4 |
| 13.1 |
| |||
2016 |
| 65.5 |
| 14.0 |
| 13.7 |
| |||
2017 - 2021 |
| 315.5 |
| 78.6 |
| 77.3 |
| |||
* Net of participant contributions
| Millions of dollars | Pension Benefits | Other Postretirement Benefits | ||||||
| 2014 | $ | 61.5 | $ | 11.7 | ||||
| 2015 | 61.2 | 12.6 | ||||||
| 2016 | 63.8 | 13.4 | ||||||
| 2017 | 65.8 | 14.1 | ||||||
| 2018 | 66.1 | 14.7 | ||||||
| 2019-2023 | 338.4 | 82.4 | ||||||
Net Periodic Benefit Cost (Income)
|
| Pension Benefits |
| Other |
| ||||||||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| 2011 |
| 2010 |
| 2009 |
| ||||||
Service cost |
| $ | 18.3 |
| $ | 17.9 |
| $ | 15.5 |
| $ | 4.3 |
| $ | 4.2 |
| $ | 3.7 |
|
Interest cost |
| 43.5 |
| 44.0 |
| 44.9 |
| 12.2 |
| 11.9 |
| 12.3 |
| ||||||
Expected return on assets |
| (63.7 | ) | (61.4 | ) | (50.8 | ) | n/a |
| n/a |
| n/a |
| ||||||
Prior service cost amortization |
| 7.0 |
| 7.0 |
| 7.0 |
| 1.0 |
| 1.0 |
| 1.0 |
| ||||||
Amortization of actuarial losses |
| 12.2 |
| 16.0 |
| 23.4 |
| 0.4 |
| — |
| — |
| ||||||
Transition amount amortization |
| — |
| — |
| — |
| 0.7 |
| 0.7 |
| 0.7 |
| ||||||
Net periodic benefit cost |
| $ | 17.3 |
| $ | 23.5 |
| $ | 40.0 |
| $ | 18.6 |
| $ | 17.8 |
| $ | 17.7 |
|
In February 2009,
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| Service cost | $ | 21.8 | $ | 19.6 | $ | 18.3 | $ | 5.9 | $ | 4.8 | $ | 4.3 | ||||||||||||
| Interest cost | 38.5 | 43.0 | 43.5 | 11.1 | 11.9 | 12.2 | ||||||||||||||||||
| Expected return on assets | (61.4 | ) | (59.5 | ) | (63.7 | ) | n/a | n/a | n/a | |||||||||||||||
| Prior service cost amortization | 6.0 | 7.0 | 7.0 | 0.7 | 0.9 | 1.0 | ||||||||||||||||||
| Amortization of actuarial losses | 16.9 | 18.4 | 12.2 | 3.3 | 1.4 | 0.4 | ||||||||||||||||||
| Transition obligation amortization | — | — | — | 0.3 | 0.7 | 0.7 | ||||||||||||||||||
| Curtailment loss | 9.9 | — | — | — | — | — | ||||||||||||||||||
| Net periodic benefit cost | $ | 31.7 | $ | 28.5 | $ | 17.3 | $ | 21.3 | $ | 19.7 | $ | 18.6 | ||||||||||||
gas operations through cost of service rates (see Note 2).
|
| Pension Benefits |
| Other |
| ||||||||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| 2011 |
| 2010 |
| 2009 |
| ||||||
Current year actuarial (gain)/loss |
| $ | 2.9 |
| $ | (26.4 | ) | $ | (10.4 | ) | $ | 0.4 |
| $ | (0.1 | ) | $ | 0.7 |
|
Amortization of actuarial losses |
| (0.4 | ) | (2.0 | ) | (3.7 | ) | — |
| — |
| — |
| ||||||
Amortization of prior service cost |
| (0.2 | ) | (0.1 | ) | (0.1 | ) | (0.1 | ) | — |
| (0.1 | ) | ||||||
Prior service cost OCI adjustment |
| — |
| 0.8 |
| — |
| — |
| — |
| — |
| ||||||
Amortization of transition obligation |
| — |
| — |
| — |
| (0.1 | ) | (0.1 | ) | (0.1) |
| ||||||
Total recognized in other comprehensive income |
| $ | 2.3 |
| $ | (27.7 | ) | $ | (14.2 | ) | $ | 0.2 |
| $ | (0.2 | ) | $ | 0.5 |
|
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| Current year actuarial (gain) loss | $ | (5.0 | ) | $ | 1.7 | $ | 2.9 | $ | (1.8 | ) | $ | 2.0 | $ | 0.4 | ||||||||||
| Amortization of actuarial losses | (0.5 | ) | (0.6 | ) | (0.4 | ) | (0.2 | ) | — | — | ||||||||||||||
| Amortization of prior service cost | (0.2 | ) | (0.2 | ) | (0.2 | ) | — | — | (0.1 | ) | ||||||||||||||
| Prior service cost (credit) | (0.3 | ) | — | — | — | — | — | |||||||||||||||||
| Amortization of transition obligation | — | — | — | (0.1 | ) | (0.1 | ) | (0.1 | ) | |||||||||||||||
| Total recognized in other comprehensive income | $ | (6.0 | ) | $ | 0.9 | $ | 2.3 | $ | (2.1 | ) | $ | 1.9 | $ | 0.2 | ||||||||||
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| Current year actuarial (gain) loss | $ | (157.5 | ) | $ | 45.0 | $ | 70.9 | $ | (29.9 | ) | $ | 31.4 | $ | 6.0 | ||||||||||
| Amortization of actuarial losses | (14.7 | ) | (16.0 | ) | (10.6 | ) | (2.7 | ) | (1.2 | ) | (0.3 | ) | ||||||||||||
| Amortization of prior service cost | (5.2 | ) | (6.4 | ) | (6.4 | ) | (0.6 | ) | (0.8 | ) | (0.9 | ) | ||||||||||||
| Prior service cost (credit) | (8.9 | ) | — | — | — | — | — | |||||||||||||||||
| Amortization of transition obligation | — | — | — | (0.2 | ) | (0.5 | ) | (0.5 | ) | |||||||||||||||
| Total recognized in regulatory assets | $ | (186.3 | ) | $ | 22.6 | $ | 53.9 | $ | (33.4 | ) | $ | 28.9 | $ | 4.3 | ||||||||||
|
| Pension Benefits |
| Other |
| ||||||||
|
| 2011 |
| 2010 |
| 2009 |
| 2011 |
| 2010 |
| 2009 |
|
Discount rate |
| 5.56 | % | 5.75 | % | 6.45 | % | 5.72 | % | 5.90 | % | 6.45 | % |
Expected return on plan assets |
| 8.25 | % | 8.50 | % | 8.50 | % | n/a |
| n/a |
| n/a |
|
Rate of compensation increase |
| 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % |
Health care cost trend rate |
| n/a |
| n/a |
| n/a |
| 8.00 | % | 8.50 | % | 8.00 | % |
Ultimate health care cost trend rate |
| n/a |
| n/a |
| n/a |
| 5.00 | % | 5.00 | % | 5.00 | % |
Year achieved |
| n/a |
| n/a |
| n/a |
| 2017 |
| 2017 |
| 2015 |
|
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
| 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||
| Discount rate | 4.10%/5.07% | 5.25 | % | 5.56 | % | 4.19 | % | 5.35 | % | 5.72 | % | ||||||
| Expected return on plan assets | 8.00 | % | 8.25 | % | 8.25 | % | n/a | n/a | n/a | ||||||||
| Rate of compensation increase | 3.75%/3.00% | 4.00 | % | 4.00 | % | 3.75 | % | 4.00 | % | 4.00 | % | ||||||
| Health care cost trend rate | n/a | n/a | n/a | 7.80 | % | 8.20 | % | 8.00 | % | ||||||||
| Ultimate health care cost trend rate | n/a | n/a | n/a | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||
| Year achieved | n/a | n/a | n/a | 2020 | 2020 | 2017 | |||||||||||
compensation increase were changed in connection with the September 1, 2013 remeasurement.
Millions of Dollars |
| Pension |
| Other |
| ||
Actuarial loss |
| $ | 0.6 |
| — |
| |
Prior service cost |
| 0.2 |
| $ | 0.1 |
| |
Transition obligation |
| — |
| 0.1 |
| ||
Total |
| $ | 0.8 |
| $ | 0.2 |
|
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||
| Actuarial loss | $ | 0.2 | — | ||||
| Prior service cost | 0.1 | — | |||||
| Total | $ | 0.3 | — | ||||
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||
| Actuarial loss | $ | 4.3 | $ | 0.4 | ||||
| Prior service cost | 3.5 | 0.3 | ||||||
| Total | $ | 7.8 | $ | 0.7 | ||||
not significant.
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.
s
2011.
Nonvested Shares |
| Shares |
| Weighted Average |
| |
Nonvested at January 1, 2009 |
| 74,588 |
| $ | 37.33 |
|
Forfeited |
| (2,399 | ) | 37.33 |
| |
Nonvested at December 31, 2009 |
| 72,189 |
| 37.33 |
| |
Vested |
| (72,189 | ) | 37.33 |
| |
Nonvested at December 31, 2010 |
| — |
|
|
| |
Nonvested shares were granted at a price corresponding to the opening price of SCANA common stockprevious such awards on the dateCompany's results of the grant. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized. The Company expensed compensation costs for nonvested shares of $0.7 million in each of 2010operations, cash flows and 2009 and recognized related tax benefits of $0.3 million in each of 2010 and 2009. The Company capitalized compensation costs of $0.1 million in each of 2010 and 2009.
A summary of activity related to nonqualified stock options follows:
Stock Options |
| Number of |
| Weighted Average |
| |
Outstanding-January 1, 2009 |
| 106,464 |
| $ | 27.44 |
|
Exercised |
| (2,875 | ) | 27.50 |
| |
Outstanding-December 31, 2009 |
| 103,589 |
| 27.44 |
| |
Exercised |
| (53,246 | ) | 27.40 |
| |
Outstanding-December 31, 2010 |
| 50,343 |
| 27.49 |
| |
Exercised |
| (40,267 | ) | 27.48 |
| |
Outstanding-December 31, 2011 |
| 10,076 |
| 27.52 |
| |
No stock options were granted or forfeited and all options were fully vested during the periods presented. The options expire ten years after their respective grant dates, and all options currently outstanding will expire in 2012. At December 31, 2011, all outstanding options were currently exercisable at a price of $27.52, and had a weighted-average remaining contractual life of less than one year.
The exercise of stock options during the periods presented were satisfied using original issue shares. For the years ended December 31, 2011, 2010 and 2009, cash realized upon the exercise of options and related tax benefitsfinancial position were not significant.
SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to the nuclear facilitySummer Station Unit 1 for property damage and outage costs up to $2.75 billion.$2.75 billion resulting from an event of 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 Ownersowners of the New Units up to $500$500 million in limits of 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 premiums, SCE&G’s portion of the prospectiveretrospective premium assessment would not exceed $37.3 million.
$41.6 million.
Environmental
on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.4 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court
SCE&G has been named, along with 53 others, byfinalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020.
TableHigh-Level Radioactive Waste with the DOE in 1983. As of Contents
December 31, 2013, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and has commenced construction of a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available.
In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. This settlement did not have a material impact on the Company’s results of operations, cash flows or financial condition.
|
| Millions of dollars |
| |
2012 |
| $ | 11 |
|
2013 |
| 10 |
| |
2014 |
| 4 |
| |
2015 |
| 2 |
| |
2016 |
| 1 |
| |
Thereafter |
| 28 |
| |
Total |
| $ | 56 |
|
Millions of dollars 2014 $ 7 2015 6 2016 4 2017 2 2018 1 Thereafter 21 Total $ 41
Purchase Commitments
The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, nuclear fuel contracts, construction projects and other commitments totaled $1.7 billion in 2011, $1.9 billion in 2010 and $1.7 billion in 2009. Future payments under such purchase commitments are as follows:
|
| Millions of dollars |
| |
2012 |
| $ | 1,542 |
|
2013 |
| 1,037 |
| |
2014 |
| 897 |
| |
2015 |
| 804 |
| |
2016 |
| 801 |
| |
Thereafter |
| 1,108 |
| |
Total |
| $ | 6,189 |
|
Forward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts.
Guarantees
The CompanySCANA issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues. The CompanySCANA is not required to recognize a liability for such guarantees issued on behalf of its subsidiaries unless it becomes probable that performance under the guarantees will be required. The CompanySCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2011,2013, the maximum future payments (undiscounted) that the CompanySCANA could be required to make under guarantees totaled $1.5 billion.
approximately $1.6 billion.
Millions of dollars |
| 2011 |
| 2010 |
| ||
Beginning balance |
| $ | 497 |
| $ | 477 |
|
Liabilities incurred |
| 1 |
| 1 |
| ||
Liabilities settled |
| (4 | ) | (1 | ) | ||
Accretion expense |
| 23 |
| 25 |
| ||
Revisions in estimated cash flows |
| (44 | ) | (5 | ) | ||
Ending Balance |
| $ | 473 |
| $ | 497 |
|
86
| Millions of dollars | 2013 | 2012 | ||||||
| Beginning balance | $ | 561 | $ | 473 | ||||
| Liabilities incurred | 6 | — | ||||||
| Liabilities settled | (4 | ) | (5 | ) | ||||
| Accretion expense | 25 | 24 | ||||||
| Revisions in estimated cash flows | (12 | ) | 69 | |||||
| Ending balance | $ | 576 | $ | 561 | ||||
11. AFFILIATED TRANSACTIONS
2011.
2012.
The Company’s reportable
The Company’s regulated
Disclosure of Reportable Segments (Millions of dollars)
|
| Electric |
| Gas |
| Retail Gas |
| Energy |
| All |
| Adjustments/ |
| Consolidated |
| |||||||
2011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External Revenue |
| $ | 2,424 |
| $ | 840 |
| $ | 479 |
| $ | 657 |
| $ | 41 |
| $ | (32 | ) | $ | 4,409 |
|
Intersegment Revenue |
| 8 |
| 1 |
| — |
| 188 |
| 406 |
| (603 | ) | — |
| |||||||
Operating Income |
| 616 |
| 132 |
| n/a |
| n/a |
| 18 |
| 47 |
| 813 |
| |||||||
Interest Expense |
| 23 |
| 24 |
| 1 |
| — |
| 3 |
| 233 |
| 284 |
| |||||||
Depreciation and Amortization |
| 271 |
| 65 |
| 3 |
| — |
| 25 |
| (18 | ) | 346 |
| |||||||
Income Tax Expense |
| 5 |
| 30 |
| 16 |
| 3 |
| 10 |
| 104 |
| 168 |
| |||||||
Income Available to Common Shareholders |
| n/a |
| n/a |
| 24 |
| 4 |
| (6 | ) | 365 |
| 387 |
| |||||||
Segment Assets |
| 8,222 |
| 2,179 |
| 185 |
| 114 |
| 1,377 |
| 1,457 |
| 13,534 |
| |||||||
Expenditures for Assets |
| 806 |
| 140 |
| — |
| 1 |
| 17 |
| (18 | ) | 946 |
| |||||||
Deferred Tax Assets |
| 9 |
| 12 |
| 9 |
| 9 |
| 17 |
| (30 | ) | 26 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External Revenue |
| $ | 2,367 |
| $ | 979 |
| $ | 553 |
| $ | 692 |
| $ | 37 |
| $ | (27 | ) | $ | 4,601 |
|
Intersegment Revenue |
| 7 |
| 1 |
| — |
| 182 |
| 410 |
| (600 | ) | — |
| |||||||
Operating Income |
| 554 |
| 140 |
| n/a |
| n/a |
| 19 |
| 55 |
| 768 |
| |||||||
Interest Expense |
| 22 |
| 24 |
| 1 |
| — |
| 3 |
| 216 |
| 266 |
| |||||||
Depreciation and Amortization |
| 263 |
| 63 |
| 4 |
| — |
| 29 |
| (24 | ) | 335 |
| |||||||
Income Tax Expense |
| (1 | ) | 28 |
| 19 |
| 2 |
| 10 |
| 101 |
| 159 |
| |||||||
Income Available to Common Shareholders |
| n/a |
| n/a |
| 31 |
| 4 |
| (6 | ) | 347 |
| 376 |
| |||||||
Segment Assets |
| 7,882 |
| 2,161 |
| 196 |
| 116 |
| 1,322 |
| 1,291 |
| 12,968 |
| |||||||
Expenditures for Assets |
| 752 |
| 107 |
| — |
| — |
| 41 |
| (24 | ) | 876 |
| |||||||
Deferred Tax Assets |
| 5 |
| 11 |
| 9 |
| 5 |
| 18 |
| (27 | ) | 21 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External Revenue |
| $ | 2,141 |
| $ | 948 |
| $ | 522 |
| $ | 616 |
| $ | 37 |
| $ | (27 | ) | $ | 4,237 |
|
Intersegment Revenue |
| 8 |
| 1 |
| — |
| 161 |
| 416 |
| (586 | ) | — |
| |||||||
Operating Income |
| 504 |
| 132 |
| n/a |
| n/a |
| 19 |
| 44 |
| 699 |
| |||||||
Interest Expense |
| 15 |
| 21 |
| — |
| — |
| 4 |
| 193 |
| 233 |
| |||||||
Depreciation and Amortization |
| 244 |
| 61 |
| 4 |
| — |
| 28 |
| (21 | ) | 316 |
| |||||||
Income Tax Expense |
| — |
| 28 |
| 15 |
| 2 |
| 9 |
| 113 |
| 167 |
| |||||||
Income Available to Common Shareholders |
| n/a |
| n/a |
| 24 |
| 3 |
| (12 | ) | 333 |
| 348 |
| |||||||
Segment Assets |
| 7,312 |
| 2,040 |
| 183 |
| 99 |
| 1,205 |
| 1,255 |
| 12,094 |
| |||||||
Expenditures for Assets |
| 817 |
| 76 |
| — |
| 1 |
| 130 |
| (110 | ) | 914 |
| |||||||
Deferred Tax Assets |
| — |
| 10 |
| 8 |
| 6 |
| 19 |
| (43 | ) | — |
| |||||||
Electric Operations | Gas Distribution | Retail Gas Marketing | Energy Marketing | All Other | Adjustments/ Eliminations | Consolidated Total | |||||||||||||||||||||
| 2013 | |||||||||||||||||||||||||||
| External Revenue | $ | 2,423 | $ | 942 | $ | 465 | $ | 652 | $ | 40 | $ | (27 | ) | $ | 4,495 | ||||||||||||
| Intersegment Revenue | 6 | 1 | — | 167 | 416 | (590 | ) | — | |||||||||||||||||||
| Operating Income | 679 | 153 | — | n/a | 27 | 51 | 910 | ||||||||||||||||||||
| Interest Expense | 19 | 22 | 1 | — | 4 | 251 | 297 | ||||||||||||||||||||
| Depreciation and Amortization | 297 | 70 | 3 | — | 26 | (18 | ) | 378 | |||||||||||||||||||
| Income Tax Expense | 6 | 33 | 15 | 4 | 14 | 151 | 223 | ||||||||||||||||||||
| Net Income | n/a | n/a | 24 | 6 | (2 | ) | 443 | 471 | |||||||||||||||||||
| Segment Assets | 9,488 | 2,340 | 172 | 133 | 1,378 | 1,653 | 15,164 | ||||||||||||||||||||
| Expenditures for Assets | 907 | 140 | — | 1 | 31 | 27 | 1,106 | ||||||||||||||||||||
| Deferred Tax Assets | 10 | 27 | 8 | 2 | 14 | (61 | ) | — | |||||||||||||||||||
| 2012 | |||||||||||||||||||||||||||
| External Revenue | $ | 2,446 | $ | 764 | $ | 413 | $ | 543 | $ | 45 | $ | (35 | ) | $ | 4,176 | ||||||||||||
| Intersegment Revenue | 7 | 1 | — | 125 | 416 | (549 | ) | — | |||||||||||||||||||
| Operating Income | 668 | 141 | n/a | n/a | 22 | 28 | 859 | ||||||||||||||||||||
| Interest Expense | 21 | 23 | 1 | — | 3 | 247 | 295 | ||||||||||||||||||||
| Depreciation and Amortization | 278 | 67 | 3 | — | 25 | (17 | ) | 356 | |||||||||||||||||||
| Income Tax Expense | 7 | 32 | 7 | 3 | 15 | 118 | 182 | ||||||||||||||||||||
| Net Income | n/a | n/a | 11 | 5 | 1 | 403 | 420 | ||||||||||||||||||||
| Segment Assets | 8,989 | 2,292 | 153 | 122 | 1,415 | 1,645 | 14,616 | ||||||||||||||||||||
| Expenditures for Assets | 999 | 123 | — | 1 | 14 | (60 | ) | 1,077 | |||||||||||||||||||
| Deferred Tax Assets | 9 | 26 | 10 | 4 | 17 | (55 | ) | 11 | |||||||||||||||||||
| 2011 | |||||||||||||||||||||||||||
| External Revenue | $ | 2,424 | $ | 840 | $ | 479 | $ | 657 | $ | 41 | $ | (32 | ) | $ | 4,409 | ||||||||||||
| Intersegment Revenue | 8 | 1 | — | 188 | 406 | (603 | ) | — | |||||||||||||||||||
| Operating Income | 616 | 132 | n/a | n/a | 18 | 47 | 813 | ||||||||||||||||||||
| Interest Expense | 23 | 24 | 1 | — | 3 | 233 | 284 | ||||||||||||||||||||
| Depreciation and Amortization | 271 | 65 | 3 | — | 25 | (18 | ) | 346 | |||||||||||||||||||
| Income Tax Expense | 5 | 30 | 16 | 3 | 10 | 104 | 168 | ||||||||||||||||||||
| Net Income | n/a | n/a | 24 | 4 | (6 | ) | 365 | 387 | |||||||||||||||||||
| Segment Assets | 8,222 | 2,179 | 185 | 114 | 1,377 | 1,457 | 13,534 | ||||||||||||||||||||
| Expenditures for Assets | 806 | 140 | — | 1 | 17 | (18 | ) | 946 | |||||||||||||||||||
| Deferred Tax Assets | 9 | 12 | 9 | 9 | 17 | (30 | ) | 26 | |||||||||||||||||||
the Company's regulated reportable segments.
88
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
|
| First |
| Second |
| Third |
| Fourth |
| Annual |
| |||||
2011 Millions of dollars, except per share amounts |
|
|
|
|
|
|
|
|
|
|
| |||||
Total operating revenues |
| $ | 1,281 |
| $ | 1,000 |
| $ | 1,092 |
| $ | 1,036 |
| $ | 4,409 |
|
Operating income |
| 248 |
| 142 |
| 215 |
| 208 |
| 813 |
| |||||
Income available to common shareholders |
| 128 |
| 56 |
| 105 |
| 98 |
| 387 |
| |||||
Basic earnings per share |
| 1.00 |
| .44 |
| .81 |
| .76 |
| 3.01 |
| |||||
Diluted earnings per share |
| 1.00 |
| .43 |
| .81 |
| .75 |
| 2.97 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2010 Millions of dollars, except per share amounts |
|
|
|
|
|
|
|
|
|
|
| |||||
Total operating revenues |
| $ | 1,428 |
| $ | 939 |
| $ | 1,088 |
| $ | 1,146 |
| $ | 4,601 |
|
Operating income |
| 230 |
| 137 |
| 196 |
| 205 |
| 768 |
| |||||
Income available to common shareholders |
| 127 |
| 54 |
| 101 |
| 94 |
| 376 |
| |||||
Basic earnings per share |
| 1.02 |
| .43 |
| .80 |
| .74 |
| 2.99 |
| |||||
Diluted earnings per share |
| 1.02 |
| .43 |
| .79 |
| .74 |
| 2.98 |
| |||||
| Millions of dollars, except per share amounts | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Annual | |||||||||||||||
| 2013 | ||||||||||||||||||||
| Total operating revenues | $ | 1,311 | $ | 1,016 | $ | 1,051 | $ | 1,117 | $ | 4,495 | ||||||||||
| Operating income | 293 | 189 | 255 | 173 | 910 | |||||||||||||||
| Net income | 151 | 85 | 131 | 104 | 471 | |||||||||||||||
| Basic earnings per share | 1.13 | .60 | .94 | .73 | 3.40 | |||||||||||||||
| Diluted earnings per share | 1.11 | .60 | .94 | .73 | 3.39 | |||||||||||||||
| 2012 | ||||||||||||||||||||
| Total operating revenues | $ | 1,107 | $ | 908 | $ | 1,038 | $ | 1,123 | $ | 4,176 | ||||||||||
| Operating income | 238 | 171 | 238 | 212 | 859 | |||||||||||||||
| Net income | 121 | 72 | 122 | 105 | 420 | |||||||||||||||
| Basic earnings per share | .93 | .55 | .93 | .79 | 3.20 | |||||||||||||||
| Diluted earnings per share | .91 | .54 | .91 | .78 | 3.15 | |||||||||||||||
91
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workforce. Nationwide the civilian labor force was 62.8% at December 31, 2013, matching a 35-year low. containment vessel bottom head. The 329,000 customers. equity of 10.25%. retain large commercial and industrial customers. for the foreseeable future. Millions of dollars 2011 Change 2010 Change 2009 Net income $ 316.1 4.0 % $ 304.0 5.7 % $ 287.5 Net income increased Millions of dollars 2011 2010 2009 Income Statement Impact: Reduction in employee benefit costs — $ (2.5 ) $ (4.4 ) Other expense (income) $ 0.2 (4.2 ) (4.0 ) Balance Sheet Impact: Increase in capital expenditures 3.4 5.3 9.1 Component of amount receivable from Summer Station co-owner 1.2 1.7 2.7 Increase in regulatory asset 9.1 18.6 31.2 Total Pension Cost $ 13.9 $ 18.9 $ 34.6 electric operations and $0.2 million for gas operations.SCE&G is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, and transportation of natural gas. SCE&G’s business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 22,600 square miles.Key Earnings Drivers and OutlookDuring 2011,2013, economic growth showed modest signs of improvementcontinued to improve in the southeast. Significant industrial announcements in SCE&G’s service territory were made during the year.year, and announcements made in previous years began to materialize. In addition, the Port of Charleston continues to see increased traffic, with container volume up 5.7% over 2012. SCE&G’s residential and commercial customer growth rates also were positive, though customer usage by existing customers continued to decline.positive. At December 31, 2011,2013, a preliminary estimate of seasonally adjusted unemployment for South Carolina was 9.5%6.6%. Though improved from the 10.9%8.6% unemployment rate at December 31, 2010, unemployment remains high and continues2012, the improvement may be due in part to slowpeople leaving the pace of economic recovery in South Carolina.Over the next five years, key earnings drivers for SCE&G will be additions to utility rate base, consisting primarily of capital expenditures for new generating capacity, environmental facilities and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage and the level of growth of operation and maintenance expenses and taxes.Electric OperationsThe electric operations segment is comprised of the electric operations of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 20112013 SCE&G provided electricity to approximately 664,000 customers in an area covering nearly 17,000 square miles.678,000 customers. GENCO owns a coal-fired generating station and sells electricity solely to SCE&G. Fuel Company acquires, owns, and provides financing for and sells at cost to SCE&G’s&G nuclear fuel, certain fossil fuels and emission and other environmental allowances.Operating results for electric operations are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control growth in costs. Through 2013, the effect of weather on operating results was largely mitigated by the eWNA; however, the eWNA was discontinued pursuant to an SCPSC order effective with the first billing cycle of January 2014. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity is 10.7%in 2013 was 10.25% for non-BLRA expenditures, and 11.0% for BLRA-related expenditures. As further described in Note 2 to the consolidated financial statements, SCE&G's allowed return on equity for non-BLRA expenditures was 10.7% prior to 2013. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has subsequently retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (2012 summer rating) of 730 MW. As of December 31, 2013, three of these units have been retired. For additional information, see Note 1 and Note 2 to the consolidated financial statements.New Nuclear ConstructionSCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, ofis constructing two 1,117-MW1,250 MW (1,117 MW, net) nuclear generation units to be constructed at the site of Summer Station,Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for 55 percent of the cost of and receiving 55 percent ofreceive the output andfrom the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining 45 percent.share. SCE&G's current ownership share in the New Units is 55%. Under these agreements,an agreement signed in January 201493(and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units. Under the terms of this agreement, SCE&G will have the primary responsibility for oversight of the construction ofacquire a one percent ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will be responsible foracquire the final two percent no later than the second anniversary of such commercial operation date. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units as they come online.SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units. Units are complete.SCE&G’s&G expects Unit 2 to be placed in service in the fourth quarter of 2017 or the first quarter of 2018, with Unit 3's in-service date approximately 12 months later. SCE&G's share of the estimated cash outlays (future value, excluding AFC) for its current 55% ownership share totals approximately $6$5.4 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. The successful completionIn addition, under the terms of the New Units would result in a substantial increase in SCE&G’s utility plant in service. Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to SCE&G.Asagreement previously reported,described, SCE&G has been advised byagreed to pay an amount equal to Santee CooperCooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest.Significant recent developments in new nuclear construction include the following:In the first quarter of 2013, initial pouring of the Unit 2 nuclear island basemat was completed. The basemat provides a foundation for the containment vessel, shield building and auxiliary building that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, includingmake up the level of its participationnuclear island. The Unit 3 nuclear island basemat was completed in the New Units. Santee Cooper has entered into a letterfourth quarter of intent with Duke2013.In April 2013, the 500-ton CR-10 module was set on the Unit 2 basemat. CR-10 supports the containment vessel. Construction of Unit 3's CR-10 module is currently underway.In May 2013, the containment vessel bottom head for Unit 2 was put in place. The containment vessel will house numerous reactor system components, such as the reactor vessel, steam generator and pressurizer. Work continues in building containment vessel rings that may result in Duke acquiring a portion of Santee Cooper’s ownership interestwill be placed on the containment vessel bottom head for Unit 2.In September 2013, the reactor vessel cavity for Unit 2 (CA-04 module) was placed in the New Units.Consortiumreactor vessel cavity will house the reactor vessel, which in turn will house the fuel assemblies. The reactor vessel for Unit 2 is on-site.Fabrication has recently performed an impact study, at SCE&G’s request, relatedbegun for Unit 2's steam generator and refueling canal module (CA-01 module) that will be located inside the containment vessel.Ring 1 of the Unit 2 containment vessel is scheduled to various cost and timing alternatives arising frombe placed on the delaycontainment vessel bottom head in the issuance datesecond quarter 2014. Ring 2 is scheduled to be placed in the fourth quarter of 2014.While progress has been made with production, quality assurance and quality control issues, the schedule for fabrication of sub-modules at the contractor facility remains a focus area for the project.During the fourth quarter of 2013, the Consortium began a full re-baselining of the COL from mid-2011, which wasUnit 2 and Unit 3 construction schedules. SCE&G anticipates that this revised schedule and the date assumed whencost estimate at completion for all non-firm and fixed scopes of work will be finalized in the EPC Contract was signedthird quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in 2008,light of the new schedule.For additional information on these and other matters, see New Nuclear Construction Matters herein and Note 2 and Note 10 to the early-2012 issuance date currently anticipated by SCE&G. SCE&G has recently informed the Consortium that it intends to pursue the alternative that would delay the substantial completion dateconsolidated financial statements.EnvironmentalAs part of the first New UnitPresident's Climate Action Plan and accelerateby Presidential Memorandum issued June 25, 2013, the substantial completion dateEPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the final rule, but does not plan to construct new coal-fired units in the near future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015.94The CWA provides for the secondimposition of effluent limitations that require treatment for wastewater discharges. New Unitfederal effluent limitation guidelines for steam electric generating units were published in the Federal Register on June 7, 2013, and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, whichELG Rule is the reactorexpected to be used forfinalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020. Additionally, the New Units. This certificationEPA is a necessary step before the NRC canexpected to issue a COLrule that modifies requirements for existing cooling water intake structures in early 2014, and Congress is expected to consider further amendments to the New Units. CWA.In October 2011, the NRC conductedresponse to a mandatory hearing regarding the issuance offederal court order to establish a COLdefinite timeline for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.See additional discussion at OTHER MATTERS - Nuclear Generation.EnvironmentalSignificant federal legislative initiatives related to energy were unsuccessful in 2011, and Consolidated SCE&G expects such legislative initiatives will be hampered through 2012, due to each chamber of Congress being controlled by different political parties. The EPA, however, did issue new rules in 2011 related to air quality, including CSAPR and MATS, which require reductions in power plant emissions of sulfur dioxide, nitrogen oxide and mercury, among other substances. Though implementation of CSAPR was stayed by the United States Court of Appeals for the District of Columbia pending judicial review, Consolidated SCE&G cannot predict the outcome that judicial review will have on the rule’s implementation. In 2012, additional significant regulatory initiatives bya CCR rule, the EPA and other federal agencieshas said it will likely proceed. These initiatives may require Consolidated SCE&G to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. Consolidated SCE&G cannot predict whether such initiatives will be enacted, and if they are, the conditions they would impose on utilities.The EPA has stated its intention to propose, in late 2012,issue new federal regulations affecting the management and disposal of CCR,CCRs, such as ash.ash, by December 14, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.The EPA is also expectedabove environmental initiatives and other similar issues are described in Environmental Matters herein and in Note 10 to issue regulations during 2012 for cooling water intake structures to meet BACT at existing power generating stations. Whilethe consolidated financial statements. Unless otherwise noted, Consolidated SCE&G cannot predict how extensive the regulationswhen regulatory rules or legislative requirements for any of these initiatives will be,become final, if at all, or what conditions they may impose on it, if any. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.Gas DistributionThe Gas Distribution segment, comprised of the local distribution operations of SCE&G, is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of South Carolina. At December 31, 20112013 this segment provided natural gas to approximately 317,000 customers in areas covering 22,600 square miles.Operating results for gas distribution are primarily influenced by customer demand for natural gas, rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity.Demand for natural gas is primarily affected by weather, customer growth, the economy and for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and will impact SCE&G’s ability toOne effect ofIn addition, the sluggish economy has been an overall decrease in demand for natural gas which, coupled with discoveriesproduction of shale gas in the United States has resulted in significantly lower prices for this commodity, in 2010 and 2011. Low natural gas commoditysuch prices are expected to continue in 2012 and beyond.Net IncomeNet income for Consolidated SCE&G was as follows:Millions of dollars 2013 Change 2012 Change 2011 Net income $ 390.8 11.0 % $ 352.0 11.4 % $ 316.1 ·20112013 vs 20102012$46.7due to higher electric and gas margins. These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest expense, further described below.2012 vs 2011 Net income increased due to higher electric and gas margins. These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest expense, further described below. 95Dividends DeclaredConsolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2013 and 2012:Declaration Date Dividend Amount Quarter Ended Payment Date February 20, 2013 $64.0 million March 31, 2013 April 1, 2013 April 25, 2013 $63.8 million June 30, 2013 July 1, 2013 July 31, 2013 $67.5 million September 30, 2013 October 1, 2013 October 31, 2013 $61.7 million December 31, 2013 January 1, 2014 February 15, 2012 $53.4 million March 31, 2012 April 1, 2012 May 3, 2012 $54.1 million June 30, 2012 July 1, 2012 August 2, 2012 $55.8 million September 30, 2012 October 1, 2012 October 24, 2012 $45.6 million December 31, 2012 January 1, 2013 When a dividend payment date falls on a weekend or holiday, the payment is made the following business day.Electric OperationsElectric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows:Millions of dollars 2013 Change 2012 Change 2011 Operating revenues $ 2,430.5 (0.9 )% $ 2,453.1 0.9 % $ 2,432.2 Less: Fuel used in generation 751.0 (11.0 )% 844.2 (8.5 )% 922.5 Purchased power 43.0 53.0 % 28.1 46.4 % 19.2 Margin $ 1,636.5 3.5 % $ 1,580.8 6.1 % $ 1,490.5 2013 vs 2012 Margin increased primarily due to base rate increases under the BLRA of $54.2 million and higher electric base rates of $67.3 million approved in the December 2012 rate order. Additionally, pursuant to accounting orders of the SCPSC, 2013's electric margin reflects downward adjustments of $50.1 million to revenue. Such adjustments are fully offset by the recognition within other income of gains realized upon the settlement of certain derivative interest rate contracts, which had been deferred as regulatory liabilities. See Note 2 to the consolidated financial statements. 2012 vs 2011 Margin increased primarily by $54.4 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA, by $3.7 million due to customer growth and by $11.0 million due to the expiration of a decrement rider approved in the 2010 retail electric base rate case. 96Sales volumes (in GWh) related to the electric margin above, by class, were as follows:Classification 2013 Change 2012 Change 2011 Residential 7,571 — 7,571 (8.0 )% 8,232 Commercial 7,205 (1.2 )% 7,291 (1.4 )% 7,397 Industrial 6,000 2.8 % 5,836 (1.7 )% 5,938 Other 581 (0.9 )% 586 2.4 % 572 Total retail sales 21,357 0.3 % 21,284 (3.9 )% 22,139 Wholesale 955 (63.2 )% 2,595 26.6 % 2,049 Total 22,312 (6.6 )% 23,879 (1.3 )% 24,188 2013 vs 2012 Retail sales volume increased primarily due to customer growth and the effects of weather, partially offset by lower average use. The decrease in wholesale sales is primarily due to the expiration of two customer contracts. 2012 vs 2011 Retail sales volume decreased by 983 GWh primarily due to the effects of milder weather. The increase in wholesale sales is primarily due to higher contract utilization by a wholesale customer. Gas DistributionGas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margin (including transactions with affiliates) was as follows:Millions of dollars 2013 Change 2012 Change 2011 Operating revenues $ 414.4 16.5 % $ 355.6 (8.2 )% $ 387.4 Less: Gas purchased for resale 244.1 24.2 % 196.6 (18.0 )% 239.7 Margin $ 170.3 7.1 % $ 159.0 7.7 % $ 147.7 2013 vs 2012 Margin increased primarily due to the SCPSC-approved increase in base rates under the RSA which became effective with the first billing cycle of November 2012, as well as residential and commercial customer growth. 2012 vs 2011 Margin increased $8.3 million due to the SCPSC-approved increases in retail gas base rates under the RSA which became effective with the first billing cycles of November 2011 and 2012. Sales volumes (in MMBTU) by class, including transportation gas, were as follows:Classification (in thousands) 2013 Change 2012 Change 2011 Residential 12,515 23.3 % 10,153 (13.0 )% 11,674 Commercial 12,786 9.1 % 11,723 (2.9 )% 12,071 Industrial 20,411 5.5 % 19,341 14.0 % 16,963 Transportation gas 4,801 2.0 % 4,707 7.6 % 4,376 Total 50,513 10.0 % 45,924 1.9 % 45,084 2013 vs 2012 Total sales volumes increased primarily due to customer growth, increased industrial usage and the effects of weather. 2012 vs 2011 Residential and commercial sales volume decreased primarily due to milder weather. Industrial and transportation sales volumes increased due to the competitive price of gas versus alternate fuel sources. 97Other Operating ExpensesOther operating expenses were as follows:Millions of dollars 2013 Change 2012 Change 2011 Other operation and maintenance $ 556.5 2.8 % $ 541.6 5.1 % $ 515.1 Depreciation and amortization 313.4 6.8 % 293.4 2.6 % 286.1 Other taxes 200.2 6.3 % 188.3 3.2 % 182.5 2013 vs 2012 Other operation and maintenance expenses increased by $16.7 million due to incremental expenses associated with the December 2012 SCPSC rate order and by $5.7 million due to higher electric margingeneration, transmission and by $1.0 million due to lower operation and maintenancedistribution expenses. This increase was partially offset by $4.1 million due to lower gas margin, higher depreciation expense of $9.1 million, higher property taxes of $6.2 million, higher interest expense of $11.0 million and lower AFC of $5.8 million.·2010 vs 2009Net income increased $72.7 million due to higher electric margin and $6.5 million due to higher gas margin. These increases were partially offset by lower compensation costs of $10.1 million due to reduced headcount and lower incentive compensation accruals and by other general expenses. Depreciation and amortization expense increased $13.2 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 SCPSC rate order and due to other net plant additions. Other taxes increased primarily due to higher property taxes on net property additions.2012 vs 2011 Other operation and maintenance expenses increased by $9.3 million due to higher generation, transmission and distribution expenses, of $10.4by $1.7 million due to higher general expenses and by increased$14.2 million due to higher incentive compensation of $5.6 million, byand other benefits. Depreciation and amortization expense increased interest expense of $14.2 million, by lower equity AFC of $8.8 million, byprimarily due to net property additions. Other taxes increased primarily due to higher property taxes of $7.5 million and by $12.9 million due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in 2009. In late 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.on net property additions.PensionNet Periodic Benefit CostPension Net periodic benefit cost was recorded on Consolidated SCE&G’s&G's income statements and balance sheets as follows:Millions of dollars 2013 Change 2012 Change 2011 Income Statement Impact: Employee benefit costs $ 11.0 100.0% — — — Other expense 0.6 50.0 % $ 0.4 100.0 % $ 0.2 Balance Sheet Impact: Increase in capital expenditures 6.4 12.3 % 5.7 67.6 % 3.4 Component of amount receivable from Summer Station co-owner 2.5 13.6 % 2.2 83.3 % 1.2 Increase in regulatory asset 5.5 (63.3 )% 15.0 64.8 % 9.1 Net periodic benefit cost $ 26.0 11.6 % $ 23.3 67.6 % $ 13.9 Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’sSCPSC's July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension costcosts related to retail electric and gas operations that otherwise would have been charged to expense. TheseEffective in January 2013, in connection with the December 2012 rate order, SCE&G began amortizing previously deferred pension cost related to retail electric operations totaling approximately $63 million over approximately 30 years (see Note 2) and recovering current pension costs willrelated to retail electric operations through a rate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, deferred until such time as future rate recoverypension cost related to gas operations of approximately $14 million is provided for by the SCPSC.No contributionbeing amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to gas operations through cost of service rates (see Note 2 to the pension trust was necessary, nor did limitations on benefit payments apply, in orconsolidated financial statements). In 2013, such amortizations totaled approximately $2.0 million for any period reported.98Other Income (Expense)Other income (expense) includes the results of certain non-utility activities. Components of other income (expense), were as follows:Millions of dollars 2013 Change 2012 Change 2011 Other income $ 52.7 * $ 0.4 (91.8 )% $ 4.9 Other expense (17.5 ) (2.2 )% (17.9 ) 51.7 % (11.8 ) Total $ 35.2 * $ (17.5 ) * $ (6.9 ) *Greater than 100%2013 vs 2012 Total other income (expense) increased primarily due to the recognition, pursuant to SCPSC accounting orders, of $50.1 million of gains realized upon the 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 regulatory liabilities. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income. 2012 vs 2011 Total other income (expense) decreased primarily due to higher non-utility related employee benefit costs in 2012. AFCAFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 4.5%6.6% of income before income taxes in 2013, 6.3% in 2012 and 4.5% in 2011, 6.6% in 2010 and 11.5% in 2009, respectively.
Dividends Declared
Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2011 and 2010:
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Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Operating revenues |
| $ | 2,432.2 |
| 2.5 | % | $ | 2,373.9 |
| 10.5 | % | $ | 2,148.9 |
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Less: Fuel used in generation |
| 922.5 |
| (2.6 | )% | 946.7 |
| 15.1 | % | 822.3 |
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Purchased power |
| 19.2 |
| 12.9 | % | 17.0 |
| 1.2 | % | 16.8 |
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Margin |
| $ | 1,490.5 |
| 5.7 | % | $ | 1,410.2 |
| 7.7 | % | $ | 1,309.8 |
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Sales volumes (in GWh) related to the electric margin above, by class, were as follows:
Classification |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
|
Residential |
| 8,232 |
| (6.4 | )% | 8,791 |
| 11.4 | % | 7,893 |
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Commercial |
| 7,397 |
| (3.7 | )% | 7,684 |
| 4.5 | % | 7,350 |
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Industrial |
| 5,938 |
| 1.3 | % | 5,863 |
| 10.1 | % | 5,324 |
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Other |
| 572 |
| (1.5 | )% | 581 |
| 3.4 | % | 562 |
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Total retail sales |
| 22,139 |
| (3.4 | )% | 22,919 |
| 8.5 | % | 21,129 |
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Wholesale |
| 2,049 |
| 4.3 | % | 1,965 |
| (0.5 | )% | 1,975 |
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Total |
| 24,188 |
| (2.8 | )% | 24,884 |
| 7.7 | % | 23,104 |
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Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margin (including transactions with affiliates) was as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Operating revenues |
| $ | 387.4 |
| (12.3 | )% | $ | 441.6 |
| 5.1 | % | $ | 420.1 |
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Less: Gas purchased for resale |
| 239.7 |
| (16.6 | )% | 287.4 |
| 4.0 | % | 276.3 |
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Margin |
| $ | 147.7 |
| (4.2 | )% | $ | 154.2 |
| 7.2 | % | $ | 143.8 |
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Sales volumes (in DT) by class, including transportation gas, were as follows:
Classification (in thousands) |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
|
Residential |
| 11,674 |
| (21.9 | )% | 14,954 |
| 20.7 | % | 12,386 |
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Commercial |
| 12,071 |
| (8.9 | )% | 13,255 |
| 4.1 | % | 12,736 |
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Industrial |
| 16,963 |
| 2.8 | % | 16,497 |
| 11.1 | % | 14,853 |
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Transportation gas |
| 4,376 |
| 16.7 | % | 3,749 |
| 12.8 | % | 3,323 |
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Total |
| 45,084 |
| (7.0 | )% | 48,455 |
| 11.9 | % | 43,298 |
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Other Operating Expenses
Other operating expenses were as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Other operation and maintenance |
| $ | 515.1 |
| 0.1 | % | $ | 514.4 |
| 5.0 | % | $ | 489.8 |
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Depreciation and amortization |
| 286.1 |
| 5.5 | % | 271.3 |
| 6.4 | % | 255.1 |
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Other taxes |
| 182.5 |
| 4.5 | % | 174.7 |
| 7.9 | % | 161.9 |
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Other Income (Expense)
Other income (expense) includes the results of certain non-utility activities. Components of other income (expense), were as follows:
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Other income |
| $ | 4.9 |
| (59.5 | )% | $ | 12.1 |
| (57.7 | )% | $ | 28.6 |
|
Other expense |
| (11.8 | ) | (21.9 | )% | (15.1 | ) | 33.6 | % | (11.3 | ) | |||
Total |
| $ | (6.9 | ) |
| * | $ | (3.0 | ) |
| * | $ | 17.3 |
|
*Greater than 100%
|
|
|
|
|
|
Interest Expense
Millions of dollars |
| 2011 |
| Change |
| 2010 |
| Change |
| 2009 |
| |||
Interest on long-term debt, net |
| $ | 191.0 |
| 7.3 | % | $ | 178.0 |
| 13.9 | % | $ | 156.3 |
|
Other interest expense |
| 13.5 |
| 55.2 | % | 8.7 |
| 17.6 | % | 7.4 |
| |||
Total |
| $ | 204.5 |
| 9.5 | % | $ | 186.7 |
| 14.1 | % | $ | 163.7 |
|
| Millions of dollars | 2013 | Change | 2012 | Change | 2011 | |||||||||||||
| Interest on long-term debt, net | $ | 206.8 | 3.0 | % | $ | 200.7 | 5.1 | % | $ | 191.0 | ||||||||
| Other interest expense | 10.5 | 7.1 | % | 9.8 | (27.4 | )% | 13.5 | |||||||||||
| Total | $ | 217.3 | 3.2 | % | $ | 210.5 | 2.9 | % | $ | 204.5 | ||||||||
Income Taxes
Income tax expense (and the effective tax rate) increasedyear and also decreased in 2011 over 2010 primarily2012 due to the accelerated amortizationreversal in 2012 of deferred EIZ Creditsinterest which had been accrued in 2011 related to offset undercollected fuel costs in 2010 pursuant to an SCPSC order and an increase in operating income. Incomea tax expense (and the effective tax rate) decreased in 2010 over 2009 primarily due to the above-mentioned accelerated amortization of EIZ Credits to offset undercollected fuel costs and the accelerated amortization of EIZ Credits in connection with the July 2010 retail electric rate order. (Seeuncertainty that was resolved (see Note 5 to the consolidated financial statements for reconciling differences between incomestatements).
rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.
3.48.
regulations, will depend upon its ability to attract the necessary financial capital on reasonable terms. Consolidated SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and Consolidated SCE&G continues its ongoing construction program, Consolidated SCE&G expects to seek increases in rates. Consolidated SCE&G’s future financial position and results of operations will be affected by Consolidated SCE&G’s ability to obtain adequate and timely rate and other regulatory relief.
2014.
Millions of dollars |
| 2012 |
| 2013 |
| 2014 |
| |||
Consolidated SCE&G - Normal |
|
|
|
|
|
|
| |||
Generation |
| $ | 143 |
| $ | 96 |
| $ | 79 |
|
Transmission & Distribution |
| 197 |
| 217 |
| 190 |
| |||
Other |
| 26 |
| 14 |
| 21 |
| |||
Gas |
| 49 |
| 51 |
| 57 |
| |||
Common |
| 14 |
| 18 |
| 13 |
| |||
Total Consolidated SCE&G - Normal |
| 429 |
| 396 |
| 360 |
| |||
New Nuclear |
| 954 |
| 952 |
| 727 |
| |||
Cash Requirements for Construction |
| 1,383 |
| 1,348 |
| 1,087 |
| |||
Nuclear Fuel |
| 44 |
| 110 |
| 55 |
| |||
Total Estimated Capital Expenditures |
| $ | 1,427 |
| $ | 1,458 |
| $ | 1,142 |
|
| Millions of dollars | 2014 | 2015 | 2016 | |||||||||
| Consolidated SCE&G - Normal | ||||||||||||
| Generation | $ | 136 | $ | 145 | $ | 112 | ||||||
| Transmission & Distribution | 230 | 280 | 258 | |||||||||
| Other | 14 | 25 | 19 | |||||||||
| Gas | 50 | 51 | 73 | |||||||||
| Common | 9 | 7 | 10 | |||||||||
| Total Consolidated SCE&G - Normal | 439 | 508 | 472 | |||||||||
| New Nuclear (including transmission) | 950 | 905 | 667 | |||||||||
| Cash Requirements for Construction | 1,389 | 1,413 | 1,139 | |||||||||
| Nuclear Fuel | 67 | 30 | 147 | |||||||||
| Total Estimated Capital Expenditures | $ | 1,456 | $ | 1,443 | $ | 1,286 | ||||||
|
| Payments due by period |
| |||||||||||||
Millions of dollars |
| Total |
| Less than |
| 1 - 3 years |
| 4 - 5 years |
| More than |
| |||||
Long-term and short-term debt including interest |
| $ | 7,204 |
| $ | 716 |
| $ | 746 |
| $ | 359 |
| $ | 5,383 |
|
Capital leases |
| 7 |
| 2 |
| 3 |
| 2 |
| — |
| |||||
Operating leases |
| 37 |
| 7 |
| 9 |
| — |
| 21 |
| |||||
Purchase obligations |
| 4,335 |
| 955 |
| 2,306 |
| 412 |
| 662 |
| |||||
Other commercial commitments |
| 1,991 |
| 641 |
| 557 |
| 207 |
| 586 |
| |||||
Total |
| $ | 13,574 |
| $ | 2,321 |
| $ | 3,621 |
| $ | 980 |
| $ | 6,652 |
|
| Payments due by period | ||||||||||||||||||||
| Millions of dollars | Total | Less than 1 year | 1 - 3 years | 4 - 5 years | More than 5 years | |||||||||||||||
| Long-term and short-term debt including interest | $ | 8,403 | $ | 510 | $ | 653 | $ | 1,090 | $ | 6,150 | ||||||||||
| Capital leases | 12 | 2 | 6 | 2 | 2 | |||||||||||||||
| Operating leases | 30 | 5 | 6 | 1 | 18 | |||||||||||||||
| Purchase obligations | 3,669 | 1,802 | 1,646 | 221 | — | |||||||||||||||
| Other commercial commitments | 2,524 | 527 | 713 | 571 | 713 | |||||||||||||||
| Total | $ | 14,638 | $ | 2,846 | $ | 3,024 | $ | 1,885 | $ | 6,883 | ||||||||||
Future Value |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| After 2016 |
| ||||||
Total Project Cash Outlay |
| $ | 804 |
| $ | 825 |
| $ | 558 |
| $ | 575 |
| $ | 367 |
| $ | 232 |
|
estimated $500 million SCE&G expects it will cost to acquire an additional 5% ownership in the New Units as further described in New Nuclear Construction Matters.
Included in other commercial commitments are estimated obligations for coal and nuclear fuel purchases. SCE&G also has a legal obligation associated with the decommissioning and dismantling of Summer Station Unit 1 and other conditional asset retirement obligations that are not listed in the contractual cash obligations above. See Notes 1 and 10 to the consolidated financial statements.
In addition, Consolidated SCE&G is party to certain NYMEX futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
follow.
2014.
At December 31, 2011 and 2010, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
|
| Millions of |
| ||||
|
| 2011 |
| 2010 |
| ||
Lines of credit: |
|
|
|
|
| ||
Committed long-term |
|
|
|
|
| ||
Total |
| $ | 1,100 |
| $ | 1,100 |
|
LOC advances |
| — |
| — |
| ||
Weighted average interest rate |
| — |
| — |
| ||
Outstanding commercial paper (270 or fewer days) |
| $ | 512 |
| $ | 381 |
|
Weighted average interest rate |
| .56 | % | .42 | % | ||
Letters of credit supported by an LOC |
| $ | .3 |
| $ | .3 |
|
Available |
| $ | 588 |
| $ | 719 |
|
consolidated financial statements.
on its draws, while maintaining appropriate levels of liquidity. Average short-term borrowings outstanding during 20112013 were approximately $485$369 million. Short-term cash needs were met primarily through the issuance of commercial paper.
With respect to hydroelectric projects, the
5.28.
In October 2011, SCE&G issued $30 million of 3.22% first mortgage bonds due October 18, 2021. Proceeds from the sale
In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds due February 1, 2041, which constituted a reopening of the prior offering of $250 million of 5.45% first mortgage bonds issued in January 2011. Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance other capital expenditures and for general corporate purposes.
During 2011 Consolidated SCE&G experienced net cash inflows related to financing activities of $193$49 million primarily due to the issuance of short-term and long-term debt and contributioncontributions from parent, partially offset by repayment of short- and long-term debt and payment of dividends.
Pursuant to SCPSC accounting orders, $50.1 million of such gains were recognized within other income, with such gain recognition being fully offset by downward adjustments to revenues reflected within electric margin.
environmental requirements involves significant capital and operating costs, which the CompanyConsolidated SCE&G expects to recover through existing ratemaking provisions.
These actions are expected to address many of the rules and regulations discussed herein.
To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties andproperties. In addition, SCE&G has collected funds from customers for its storm damage reserve (see Note 2 to the consolidated financial statements). As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams and applicable personnel participate inwho receive ongoing training and related simulations in advance of such storms, all in order to allow Consolidated SCE&G to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.
In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by Consolidated SCE&G. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the new source performance standards of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.
To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether Consolidated SCE&G will be affected by the initiative in the future. Consolidated SCE&G believes that any enforcement action relative to its compliance with the CAA would be without merit. Consolidated SCE&G further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with NSR.
The
for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2011,2012, the federal government has not accepted any spent fuel from Summer Station Unit 1, or any other nuclear generating facility, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and expects to be able to expand itshas commenced construction of a dry cask storage capacityfacility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1 through dry cask storage or1. SCE&G may evaluate other technology as it becomes available.
SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.
expense as incurred.
| Company | Regulatory Jurisdiction/Matters | |
| SCE&G, GENCO and Fuel Company | The CFTC to the extent they transact swaps as defined in Dodd-Frank. | |
| SCE&G | The SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; the FERC as to issuance of short-term borrowings, guarantees of short-term indebtedness, certain acquisitions and other matters; the PHMSA as to integrity management requirements for gas distribution pipeline systems; and the NRC with respect to the ownership, construction, operation and decommissioning of its currently operated and planned nuclear generating facilities. NRC jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants. | |
| SCE&G and GENCO | The FERC and DOE, under the Federal Power Act, as to the transmission of electric energy in interstate commerce, the sale of electric energy at wholesale for resale, the licensing of hydroelectric projects and certain other matters, including accounting. | |
| GENCO | The SCPSC as to the issuance of securities (other than short-term borrowings) and the FERC as to the issuance of short-term borrowings, accounting, certain acquisitions and other matters. | |
| Fuel Company | The SEC as to the issuance of certain securities. | |
SCE&G is subject to In addition, the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.
GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.
SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting.
The RSA allows natural gas distribution companies in South Carolina to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.
Effective February 12, 2010, the PHMSA issued a final rule establishing integrity management requirements for gas distribution pipeline systems. SCE&G has developed a plan and procedures to ensure that it will be fully compliant with this rule. SCE&G believes that any additional costs incurred to comply with the rule will be recoverable through rates.
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
Accounting for Pensions and Other Postretirement Benefits
SCANA recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. SCANA’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $17.3 million ($13.9 million attributable to SCE&G) recorded in 2011 reflects the use of a 5.56% discount rate, derived using a cash flow matching technique, and an assumed 8.25% long-term rate of return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.31% in 2011 would have increased SCANA’s pension cost by $1.3 million. Had the assumed long-term rate of return on assets been 8.00%, SCANA’s pension cost for 2011 would have increased by $1.9 million.
Due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, SCE&G recorded significant amounts of pension cost in 2009, 2010 and 2011 compared to the pension income recorded previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above the level that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.
The pension trust is adequately funded under current regulations, and no contributions have been required since 1997. Management does not anticipate the need to make significant pension contributions until after 2012.
SCANA accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 5.72%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $14.0 million for 2011. Had the selected discount rate been 5.47% (25 basis points lower than the discount rate referenced above), the expense for 2011 would have been $0.4 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.
Nuclear Generation
site of Summer Station,Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for 55 percent of the cost of and receiving 55 percent ofreceive the output andfrom the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining 45 percent.share. SCE&G's current ownership share in the New Units is 55%. Under these agreements,an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units. Under the terms of this agreement, SCE&G will have the primary responsibility for oversight of the construction ofacquire a one percent ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will be responsible foracquire the final two percent no later than the
SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units.Units are complete.
As In addition, under the terms of the agreement previously reported,described, SCE&G has been advised byagreed to pay an amount equal to Santee Cooper that it is reviewing certain aspectsCooper's actual cost of its capital improvement program and long-term power supply plan, including the levelpercentage conveyed as of its participation inthe date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. This transaction will not affect the payment obligations between the parties during construction for the New Units. Santee Cooper has entered into a letterUnits, nor is it anticipated that the payments would be reflected in revised rates filings under the BLRA.
The Consortium has recently performed an impact study, at SCE&G’s request, related to various costfabrication and timing alternatives arising from the delay in the issuance datedelivery of sub-modules are a focus area of the COL from mid-2011,Consortium, including sub-modules for module CA20, which wasis part of the date assumed whenauxiliary building, and CA01, which houses components inside the EPC Contract was signed in 2008,containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its fabrication is underway. CA20 is expected to be ready for placement on the early-2012 issuance date currently anticipated by SCE&G. The impact study analyzed three scenarios, including (1) compressing the construction schedule for the first New Unit but retaining the original substantial completion dates set forth in the EPC Contract, (2) extending the substantial completion date for the first New Unit to accommodate the COL delay, or (3) delaying the substantial completion datenuclear island of the first New Unit and acceleratingin the first quarter of 2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of the first New Unit during the third quarter of 2014. With this schedule, the Consortium continues to indicate that the substantial completion date forof the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's 55% share of the New Units is approximately
such impacts could be material.
On February 29, 2012, SCE&G filed
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.
In March 2011 aearthquake-generated tsunami, resulting from a massive earthquakewhich severely damaged several nuclear generating units and their back-up cooling systems in Japan. TheSCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the disaster is being evaluated world-wide,construction and numerous politicaloperation of the New Units, and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at existing nuclear facilities, as well as those planned for construction. In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G, is evaluating.pursuant to the license condition, prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, noror how such initiatives would impact SCE&G’s&G's existing Summer Station or the licensing, construction or operation of the New Units.
In December 2011,Subject to a national megawatt capacity limitation, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactorelectricity to be used for the New Units. This certification is a necessary step before the NRC can issue a COL for the New Units. In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.
Fuel Contract
On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 andproduced by the New Units through 2033.(advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the New Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), SCE&G is dependent upon Westinghousehas applied to the IRS for providing fuel assembliesits allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification. Under current provisions of the new AP1000 passive reactorsInternal Revenue Code and based on SCE&G's current 55% ownership and other assumptions regarding volumes of electricity to be generated by the New Units, the aggregate production tax credits for which SCE&G qualifies could exceed $1.3 billion over the eight year period following each of the New Units' in-service dates. In January 2014, SCE&G amended its application to include the additional 5% interest in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering supportthat it expects to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support servicesacquire. Additional production tax credits related to the New Units upon their completion and commencement of commercial operation.
5% interest could total as much as $125 million.
In July 2010,
106
Expected Maturity Date December 31, 2011 2012 2013 2014 2015 2016 Thereafter Total Fair Long-Term Debt: Fixed Rate ($) 13.3 158.2 43.7 7.3 7.2 2,940.0 3,169.7 3,857.9 Average Interest Rate (%) 4.82 7.02 4.95 5.51 5.55 5.81 5.86 — Variable Rate ($) — — — — — 68.3 68.3 68.3 Average Variable Interest Rate (%) — — — — — .16 .16 — Interest Rate Swaps: Pay Fixed/Receive Variable ($) 250.0 150.0 — — — 71.4 471.4 (75.6 ) Average Pay Interest Rate (%) 2.60 4.89 — — — 3.29 3.43 — Average Receive Interest Rate (%) .58 .58 — — — .11 .51 — Expected Maturity Date December 31, 2010 2011 2012 2013 2014 2015 Thereafter Total Fair Long-Term Debt: Fixed Rate ($) 166.5 12.0 157.3 42.7 6.7 2,596.0 2,981.2 3,243.3 Average Interest Rate (%) 6.66 4.78 7.04 4.96 5.49 5.89 5.97 — Variable Rate ($) — — — — — 71.4 71.4 71.4 Average Variable Interest Rate (%) — — — — — .40 .40 — Interest Rate Swaps: Pay Fixed/Receive Variable ($) 350.0 — — — — 71.4 421.4 (30.8 ) Average Pay Interest Rate (%) 4.73 — — — — 3.29 4.48 — Average Receive Interest Rate (%) .30 — — — — .30 .30 — Expected Maturity: 2012 2013 Purchased Call (Long): Strike Price(a) 4.41 4.25 Contract Amount(b) 10.9 0.1 Fair Value(b) 0.1 — All financial instruments held by Consolidated SCE&G described below are held for purposes other than trading.The tables below provide information about long-term debt issued by Consolidated SCE&G which is sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.
Millions of dollars
Value
Millions of dollars
Value Expected Maturity Date December 31, 2013Millions of dollars 2014 2015 2016 2017 2018 Thereafter Total FairValueLong-Term Debt: Fixed Rate ($) 45.2 9.2 108.6 8.2 717.9 3,086.5 3,975.6 4,356.6 Average Interest Rate (%) 4.84 4.73 1.11 4.96 5.95 6.62 6.32 — Variable Rate ($) — — — — — 67.8 67.8 64.9 Average Variable Interest Rate (%) — — — — — 0.11 0.11 — Interest Rate Swaps: Pay Fixed/Receive Variable ($) 600.0 650.0 — — — 71.4 1,321.4 30.6 Average Pay Interest Rate (%) 3.96 4.16 — — — 3.29 4.02 — Average Receive Interest Rate (%) 0.25 0.25 — — — 0.06 0.24 — Expected Maturity Date December 31, 2012Millions of dollars 2013 2014 2015 2016 2017 Thereafter Total FairValueLong-Term Debt: Fixed Rate ($) 159.5 45.1 8.6 8.1 7.7 3,405.9 3,634.9 4,458.0 Average Interest Rate (%) 6.98 4.84 4.85 5.01 5.12 5.60 5.65 — Variable Rate ($) — — — — — 67.8 67.8 65.8 Average Variable Interest Rate (%) — — — — — 0.17 0.17 — Interest Rate Swaps: Pay Fixed/Receive Variable ($) 600.0 300.0 — — — 71.4 971.4 (2.5 ) Average Pay Interest Rate (%) 3.01 2.48 — — — 3.29 2.87 — Average Receive Interest Rate (%) 0.31 0.31 — — — 0.13 0.29 — While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.The above tables exclude long-term debt of $15$3 million at December 31, 20112013 and $21$9 million at December 31, 2010,2012, which amounts do not have stated interest rates associated with them.For further discussion of Consolidated SCE&G’s long-term debt and interest rate derivatives, see ITEMItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — LIQUIDITY AND CAPITAL RESOURCESLiquidity and alsoCapital Resources and Notes 4 and 6 of the condensed consolidated financial statements.Commodity Price RiskThe following table provides information about SCE&G’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value represents quoted market prices.
Options(a)Weighted average, in dollars(b)Millions of dollarsSCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 to the consolidated financial statements.SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through weighted average cost of gas calculations. The offset to the change in fair value of these derivatives is deferred.108111
To the Board of Directors and Stockholder ofSouth Carolina Electric & Gas CompanyCayce, South CarolinaWe have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the “Company”"Company") as of December 31, 20112013 and 2010,2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011.2013. 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’sCompany'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’sCompany's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20112013 and 2010,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011,2013, 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 LLPCharlotte, North CarolinaFebruary 29, 201210928, 2014112
SOUTH CAROLINA ELECTRIC & GAS COMPANY
| December 31, (Millions of dollars) | 2013 | 2012 | ||||||
| Assets | ||||||||
| Utility Plant In Service | $ | 10,378 | $ | 10,096 | ||||
| Accumulated Depreciation and Amortization | (3,499 | ) | (3,322 | ) | ||||
| Construction Work in Progress | 2,682 | 2,073 | ||||||
| Plant to be Retired, Net | 177 | 362 | ||||||
| Nuclear Fuel, Net of Accumulated Amortization | 310 | 166 | ||||||
| Utility Plant, Net ($720 and $640 related to VIEs) | 10,048 | 9,375 | ||||||
| Nonutility Property and Investments: | ||||||||
| Nonutility property, net of accumulated depreciation | 69 | 57 | ||||||
| Assets held in trust, net-nuclear decommissioning | 101 | 94 | ||||||
| Other investments | 3 | 3 | ||||||
| Nonutility Property and Investments, Net | 173 | 154 | ||||||
| Current Assets: | ||||||||
| Cash and cash equivalents | 92 | 51 | ||||||
| Receivables, net of allowance for uncollectible accounts of $3 and $3 | 486 | 483 | ||||||
| Receivables-affiliated companies | 19 | 2 | ||||||
| Inventories: | ||||||||
| Fuel | 131 | 203 | ||||||
| Materials and supplies | 120 | 126 | ||||||
| Emission allowances | 1 | 1 | ||||||
| Prepayments and other | 80 | 143 | ||||||
| Total Current Assets ($147 and $206 related to VIEs) | 929 | 1,009 | ||||||
| Deferred Debits and Other Assets: | ||||||||
| Pension asset | 96 | — | ||||||
| Regulatory assets | 1,303 | 1,377 | ||||||
| Other | 151 | 189 | ||||||
| Total Deferred Debits and Other Assets ($35 and $54 related to VIEs) | 1,550 | 1,566 | ||||||
| Total | $ | 12,700 | $ | 12,104 | ||||
| December 31, (Millions of dollars) | 2013 | 2012 | ||||||
| Capitalization and Liabilities | ||||||||
| Common equity | $ | 4,372 | $ | 3,929 | ||||
| Noncontrolling interest | 117 | 114 | ||||||
| Total Equity | 4,489 | 4,043 | ||||||
| Long-Term Debt, net | 4,007 | 3,557 | ||||||
| Total Capitalization | 8,496 | 7,600 | ||||||
| Current Liabilities: | ||||||||
| Short-term borrowings | 251 | 449 | ||||||
| Current portion of long-term debt | 48 | 165 | ||||||
| Accounts payable | 241 | 281 | ||||||
| Affiliated payables | 117 | 124 | ||||||
| Customer deposits and customer prepayments | 56 | 51 | ||||||
| Taxes accrued | 223 | 151 | ||||||
| Interest accrued | 64 | 63 | ||||||
| Dividends declared | 62 | 46 | ||||||
| Derivative financial instruments | 1 | 66 | ||||||
| Other | 71 | 50 | ||||||
| Total Current Liabilities | 1,134 | 1,446 | ||||||
| Deferred Credits and Other Liabilities: | ||||||||
| Deferred income taxes, net | 1,509 | 1,479 | ||||||
| Deferred investment tax credits | 32 | 36 | ||||||
| Asset retirement obligations | 547 | 535 | ||||||
| Postretirement benefits | 173 | 254 | ||||||
| Regulatory liabilities | 732 | 665 | ||||||
| Other | 77 | 89 | ||||||
| Total Deferred Credits and Other Liabilities | 3,070 | 3,058 | ||||||
| Commitments and Contingencies (Note 10) | — | — | ||||||
| Total | $ | 12,700 | $ | 12,104 | ||||
| For the Years Ended December 31, (Millions of dollars) | 2013 | 2012 | 2011 | |||||||||
| Operating Revenues: | ||||||||||||
| Electric | $ | 2,431 | $ | 2,453 | $ | 2,432 | ||||||
| Gas | 414 | 356 | 387 | |||||||||
| Total Operating Revenues | 2,845 | 2,809 | 2,819 | |||||||||
| Operating Expenses: | ||||||||||||
| Fuel used in electric generation | 751 | 844 | 922 | |||||||||
| Purchased power | 43 | 28 | 19 | |||||||||
| Gas purchased for resale | 244 | 197 | 240 | |||||||||
| Other operation and maintenance | 557 | 542 | 515 | |||||||||
| Depreciation and amortization | 313 | 293 | 286 | |||||||||
| Other taxes | 200 | 188 | 183 | |||||||||
| Total Operating Expenses | 2,108 | 2,092 | 2,165 | |||||||||
| Operating Income | 737 | 717 | 654 | |||||||||
| Other Income (Expense): | ||||||||||||
| Other income | 53 | — | 5 | |||||||||
| Other expenses | (18 | ) | (18 | ) | (12 | ) | ||||||
| Interest charges, net of allowance for borrowed funds used during construction of $13, $11 and $7 | (217 | ) | (211 | ) | (204 | ) | ||||||
| Allowance for equity funds used during construction | 25 | 21 | 13 | |||||||||
| Total Other Expense | (157 | ) | (208 | ) | (198 | ) | ||||||
| Income Before Income Tax Expense | 580 | 509 | 456 | |||||||||
| Income Tax Expense | 189 | 157 | 140 | |||||||||
| Net Income | 391 | 352 | 316 | |||||||||
| Less Net Income Attributable to Noncontrolling Interest | 11 | 11 | 10 | |||||||||
| Earnings Available to Common Shareholder | $ | 380 | $ | 341 | $ | 306 | ||||||
| Years Ended December 31, (Millions of dollars) | 2013 | 2012 | 2011 | ||||||||||
| Net Income | $ | 391 | $ | 352 | $ | 316 | |||||||
| Other Comprehensive Income (Loss), net of tax: | |||||||||||||
| Deferred costs of employee benefit plans, net of tax $-, $- and $- | 1 | (1 | ) | (1 | ) | ||||||||
| Amortization of deferred employee benefit plan costs reclassified to net income, net of tax $-, $- and $- | — | — | — | ||||||||||
| Other Comprehensive Income (Loss) | 1 | (1 | ) | (1 | ) | ||||||||
| Total Comprehensive Income | 392 | 351 | 315 | ||||||||||
| Less comprehensive income attributable to noncontrolling interest | (11 | ) | (11 | ) | (10 | ) | |||||||
| Comprehensive income available to common shareholder | $ | 381 | $ | 340 | $ | 305 | |||||||
December 31, (Millions of dollars) 2011 2010 Assets Utility Plant In Service: $ 10,312 $ 10,112 Accumulated Depreciation and Amortization (3,367 ) (3,098 ) Construction Work in Progress 1,472 1,051 Nuclear Fuel, Net of Accumulated Amortization 171 133 Utility Plant, Net ($662 and $634 related to VIEs) 8,588 8,198 Nonutility Property and Investments: Nonutility property, net of accumulated depreciation 52 46 Assets held in trust, net-nuclear decommissioning 84 76 Other investments 2 4 Nonutility Property and Investments, Net 138 126 Current Assets: Cash and cash equivalents 16 31 Receivables, net of allowance for uncollectible accounts of $3 and $3 482 507 Receivables-affiliated companies 9 — Inventories (at average cost): Fuel 196 216 Materials and supplies 120 117 Emission allowances 2 6 Prepayments and other 82 168 Deferred income taxes 8 15 Total Current Assets ($193 and $221 related to VIEs) 915 1,060 Deferred Debits and Other Assets: Pension asset — 57 Regulatory assets 1,206 996 Other 190 137 Total Deferred Debits and Other Assets ($61 and $43 related to VIEs) 1,396 1,190 Total $ 11,037 $ 10,574 STATEMENTS OF CASH FLOWSSOUTH CAROLINA ELECTRIC & GAS COMPANYCONSOLIDATED BALANCE SHEETSFor the Years Ended December 31, (Millions of dollars) 2013 2012 2011 Cash Flows From Operating Activities: Net income $ 391 $ 352 $ 316 Adjustments to reconcile net income to net cash provided from operating activities: Losses from equity method investments 3 4 2 Deferred income taxes, net 29 116 138 Depreciation and amortization 315 294 288 Amortization of nuclear fuel 57 44 40 Allowance for equity funds used during construction (25 ) (21 ) (13 ) Carrying cost recovery (3 ) — — Changes in certain assets and liabilities: Receivables (36 ) 35 (31 ) Inventories 35 (60 ) (25 ) Prepayments (17 ) (64 ) 82 Regulatory assets 83 (158 ) (165 ) Other regulatory liabilities 54 64 (12 ) Accounts payable 5 27 (48 ) Taxes accrued 72 1 13 Interest accrued 1 9 4 Pension and other postretirement benefits (186 ) 69 70 Other assets 52 (84 ) 27 Other liabilities 22 46 (31 ) Net Cash Provided From Operating Activities 852 674 655 Cash Flows From Investing Activities: Property additions and construction expenditures (1,003 ) (978 ) (786 ) Proceeds from investments and sales of assets (including derivative collateral posted) 144 275 11 Purchase of investments (including derivative collateral posted) (116 ) (268 ) (57 ) Payments upon interest rate derivative contract settlement (49 ) — (31 ) Proceeds from interest rate derivative contract settlement 163 14 — Net Cash Used For Investing Activities (861 ) (957 ) (863 ) Cash Flows From Financing Activities: Proceeds from issuance of long-term debt 451 513 379 Contribution from parent 311 128 107 Repayment of long-term debt (251 ) (49 ) (206 ) Dividends (241 ) (202 ) (205 ) Short-term borrowings-affiliate, net (22 ) (9 ) (13 ) Short-term borrowings, net (198 ) (63 ) 131 Net Cash Provided From Financing Activities 50 318 193 Net Increase (Decrease) in Cash and Cash Equivalents 41 35 (15 ) Cash and Cash Equivalents, January 1 51 16 31 Cash and Cash Equivalents, December 31 $ 92 $ 51 $ 16 Supplemental Cash Flow Information: Cash paid for—Interest (net of capitalized interest of $13, $11 and $7) $ 200 $ 186 $ 181 —Income taxes 92 105 — Noncash Investing and Financing Activities: Accrued construction expenditures 100 116 75 Capital lease 4 8 6 Nuclear fuel purchase 98 — — See Notes to Consolidated Financial Statements.110117
December 31, (Millions of dollars) |
| 2011 |
| 2010 |
| ||
Capitalization and Liabilities |
|
|
|
|
| ||
Common equity |
| $ | 3,665 |
| $ | 3,437 |
|
Noncontrolling interest |
| 108 |
| 104 |
| ||
Total Equity |
| 3,773 |
| 3,541 |
| ||
Long-Term Debt, net |
| 3,222 |
| 3,037 |
| ||
Total Capitalization |
| 6,995 |
| 6,578 |
| ||
Current Liabilities: |
|
|
|
|
| ||
Short-term borrowings |
| 512 |
| 381 |
| ||
Current portion of long-term debt |
| 19 |
| 22 |
| ||
Accounts payable |
| 231 |
| 341 |
| ||
Affiliated payables |
| 136 |
| 140 |
| ||
Customer deposits and customer prepayments |
| 54 |
| 60 |
| ||
Taxes accrued |
| 150 |
| 137 |
| ||
Interest accrued |
| 54 |
| 50 |
| ||
Dividends declared |
| 39 |
| 54 |
| ||
Derivative liabilities |
| 2 |
| 34 |
| ||
Other |
| 61 |
| 80 |
| ||
Total Current Liabilities |
| 1,258 |
| 1,299 |
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Deferred income taxes, net |
| 1,371 |
| 1,240 |
| ||
Deferred investment tax credits |
| 40 |
| 56 |
| ||
Asset retirement obligations |
| 449 |
| 478 |
| ||
Pension and other postretirement benefits |
| 179 |
| 163 |
| ||
Regulatory liabilities |
| 575 |
| 662 |
| ||
Other |
| 170 |
| 98 |
| ||
Total Deferred Credits and Other Liabilities |
| 2,784 |
| 2,697 |
| ||
Commitments and Contingencies (Note 10) |
| — |
| — |
| ||
Total |
| $ | 11,037 |
| $ | 10,574 |
|
SOUTH CAROLINA ELECTRIC & GAS COMPANY
| Common Stock | Retained | Accumulated Other Comprehensive | Noncontrolling | Total | |||||||||||||||||||
| Millions | Shares | Amount | Earnings | Income (Loss) | Interest | Equity | |||||||||||||||||
| Balance at January 1, 2011 | 40 | $ | 1,934 | $ | 1,505 | $ | (2 | ) | $ | 104 | $ | 3,541 | |||||||||||
| Earnings available for common shareholder | 306 | 10 | 316 | ||||||||||||||||||||
| Deferred cost of employee benefit plans, net of tax $- | (1 | ) | (1 | ) | |||||||||||||||||||
| Total Comprehensive Income (Loss) | 306 | (1 | ) | 10 | 315 | ||||||||||||||||||
| Capital contributions from parent | 107 | 107 | |||||||||||||||||||||
| Cash dividends declared | (184 | ) | (6 | ) | (190 | ) | |||||||||||||||||
| Balance at December 31, 2011 | 40 | 2,041 | 1,627 | (3 | ) | 108 | 3,773 | ||||||||||||||||
| Earnings Available for Common Shareholder | 341 | 11 | 352 | ||||||||||||||||||||
| Deferred Cost of Employee Benefit Plans, net of tax $- | (1 | ) | (1 | ) | |||||||||||||||||||
| Total Comprehensive Income (Loss) | 341 | (1 | ) | 11 | 351 | ||||||||||||||||||
| Capital contributions from parent | 126 | 2 | 128 | ||||||||||||||||||||
| Cash dividends declared | (202 | ) | (7 | ) | (209 | ) | |||||||||||||||||
| Balance at December 31, 2012 | 40 | 2,167 | 1,766 | (4 | ) | 114 | 4,043 | ||||||||||||||||
| Earnings Available for Common Shareholder | 380 | 11 | 391 | ||||||||||||||||||||
| Deferred Cost of Employee Benefit Plans, net of tax $- | 1 | 1 | |||||||||||||||||||||
| Total Comprehensive Income | 380 | 1 | 11 | 392 | |||||||||||||||||||
| Capital contributions from parent | 312 | (1 | ) | 311 | |||||||||||||||||||
| Cash dividends declared | (250 | ) | (7 | ) | (257 | ) | |||||||||||||||||
| Balance at December 31, 2013 | 40 | $ | 2,479 | $ | 1,896 | $ | (3 | ) | $ | 117 | $ | 4,489 | |||||||||||
111
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, (Millions of dollars) |
| 2011 |
| 2010 |
| 2009 |
| |||
Operating Revenues: |
|
|
|
|
|
|
| |||
Electric |
| $ | 2,432 |
| $ | 2,374 |
| $ | 2,149 |
|
Gas |
| 387 |
| 441 |
| 420 |
| |||
Total Operating Revenues |
| 2,819 |
| 2,815 |
| 2,569 |
| |||
Operating Expenses: |
|
|
|
|
|
|
| |||
Fuel used in electric generation |
| 922 |
| 947 |
| 822 |
| |||
Purchased power |
| 19 |
| 17 |
| 17 |
| |||
Gas purchased for resale |
| 240 |
| 287 |
| 276 |
| |||
Other operation and maintenance |
| 515 |
| 514 |
| 490 |
| |||
Depreciation and amortization |
| 286 |
| 271 |
| 255 |
| |||
Other taxes |
| 183 |
| 175 |
| 162 |
| |||
Total Operating Expenses |
| 2,165 |
| 2,211 |
| 2,022 |
| |||
Operating Income |
| 654 |
| 604 |
| 547 |
| |||
Other Income (Expense): |
|
|
|
|
|
|
| |||
Other income |
| 5 |
| 12 |
| 28 |
| |||
Other expenses |
| (12 | ) | (15 | ) | (11 | ) | |||
Interest charges, net of allowance for borrowed funds used during construction of $7, $10 and $22 |
| (204 | ) | (186 | ) | (164 | ) | |||
Allowance for equity funds used during construction |
| 13 |
| 19 |
| 28 |
| |||
Total Other Expense |
| (198 | ) | (170 | ) | (119 | ) | |||
Income Before Income Tax Expense |
| 456 |
| 434 |
| 428 |
| |||
Income Tax Expense |
| 140 |
| 130 |
| 140 |
| |||
Net Income |
| 316 |
| 304 |
| 288 |
| |||
Less Net Income Attributable to Noncontrolling Interest |
| 10 |
| 14 |
| 7 |
| |||
Net Income Attributable to SCE&G |
| 306 |
| 290 |
| 281 |
| |||
Preferred Stock Cash Dividends Declared |
| — |
| — |
| (9 | ) | |||
Earnings Available to Common Shareholder |
| $ | 306 |
| $ | 290 |
| $ | 272 |
|
Dividends Declared on Common Stock |
| $ | 189 |
| $ | 199 |
| $ | 179 |
|
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, (Millions of dollars) |
| 2011 |
| 2010 |
| 2009 |
| ||||
Cash Flows From Operating Activities: |
|
|
|
|
|
|
| ||||
Net income |
| $ | 316 |
| $ | 304 |
| $ | 288 |
| |
Adjustments to reconcile net income to net cash provided from operating activities: |
|
|
|
|
|
|
| ||||
Losses (earnings) from equity method investments |
| 2 |
| 2 |
| — |
| ||||
Deferred income taxes, net |
| 138 |
| 234 |
| 74 |
| ||||
Depreciation and amortization |
| 288 |
| 276 |
| 266 |
| ||||
Amortization of nuclear fuel |
| 40 |
| 36 |
| 18 |
| ||||
Allowance for equity funds used during construction |
| (13 | ) | (19 | ) | (28 | ) | ||||
Carrying cost recovery |
| — |
| (3 | ) | (5 | ) | ||||
Cash provided (used) by changes in certain assets and liabilities: |
|
|
|
|
|
|
| ||||
Receivables |
| (31 | ) | (110 | ) | 91 |
| ||||
Inventories |
| (25 | ) | (5 | ) | (144 | ) | ||||
Prepayments |
| 82 |
| (87 | ) | 43 |
| ||||
Regulatory assets |
| (165 | ) | (55 | ) | (84 | ) | ||||
Other regulatory liabilities |
| (12 | ) | (11 | ) | (2 | ) | ||||
Accounts payable |
| (48 | ) | 59 |
| (1 | ) | ||||
Taxes accrued |
| 13 |
| 9 |
| 8 |
| ||||
Interest accrued |
| 4 |
| (1 | ) | 1 |
| ||||
Changes in other assets |
| 27 |
| (78 | ) | (35 | ) | ||||
Changes in other liabilities |
| 39 |
| 120 |
| (54 | ) | ||||
Net Cash Provided From Operating Activities |
| 655 |
| 671 |
| 436 |
| ||||
Cash Flows From Investing Activities: |
|
|
|
|
|
|
| ||||
Property additions and construction expenditures |
| (786 | ) | (771 | ) | (751 | ) | ||||
Proceeds from investments and sales of assets (including derivative collateral posted) |
| 11 |
| 49 |
| 27 |
| ||||
Investment in affiliate |
| — |
| 41 |
| (23 | ) | ||||
Purchase of investments (including derivative collateral posted) |
| (57 | ) | (43 | ) | (6 | ) | ||||
Settlement of interest rate contracts |
| (31 | ) | — |
| — |
| ||||
Net Cash Used For Investing Activities |
| (863 | ) | (724 | ) | (753 | ) | ||||
Cash Flows From Financing Activities: |
|
|
|
|
|
|
| ||||
Proceeds from issuance of long-term debt |
| 379 |
| 90 |
| 421 |
| ||||
Contribution from parent |
| 107 |
| 146 |
| 348 |
| ||||
Repayment of long-term debt |
| (206 | ) | (219 | ) | (423 | ) | ||||
Redemption of preferred stock |
| — |
| — |
| (113 | ) | ||||
Dividends |
| (205 | ) | (195 | ) | (182 | ) | ||||
Short-term borrowings-affiliate, net |
| (13 | ) | 1 |
| 61 |
| ||||
Short-term borrowings, net |
| 131 |
| 127 |
| 220 |
| ||||
Net Cash Provided From (Used For) Financing Activities |
| 193 |
| (50 | ) | 332 |
| ||||
Net Increase (Decrease) in Cash and Cash Equivalents |
| (15 | ) | (103 | ) | 15 |
| ||||
Cash and Cash Equivalents, January 1 |
| 31 |
| 134 |
| 119 |
| ||||
Cash and Cash Equivalents, December 31 |
| $ | 16 |
| $ | 31 |
| $ | 134 |
| |
Supplemental Cash Flow Information: |
|
|
|
|
|
|
| ||||
Cash paid for | -Interest (net of capitalized interest of $7, $9 and $22) |
| $ | 181 |
| $ | 175 |
| $ | 152 |
|
| -Income taxes |
| — |
| 31 |
| 61 |
| |||
Noncash Investing and Financing Activities: |
|
|
|
|
|
|
| ||||
Accrued construction expenditures |
| 75 |
| 168 |
| 141 |
| ||||
Capital lease |
| 6 |
| — |
| — |
| ||||
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE INCOME
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
| |||||
|
|
|
|
|
|
|
| Other |
|
|
|
|
| |||||
|
| Common Stock |
| Retained |
| Comprehensive |
| Noncontrolling |
| Total |
| |||||||
Millions |
| Shares |
| Amount |
| Earnings |
| Income (Loss) |
| Interest |
| Equity |
| |||||
Balance at January 1, 2009 |
| 40 |
| $ | 1,440 |
| $ | 1,310 |
| $ | (46 | ) | $ | 95 |
| $ | 2,799 |
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings available for common shareholder |
|
|
|
|
| 272 |
|
|
| 7 |
| 279 |
| |||||
Deferred cost of employee benefit plans, net of tax $8 |
|
|
|
|
|
|
| 13 |
|
|
| 13 |
| |||||
Total Comprehensive Income |
|
|
|
|
| 272 |
| 13 |
| 7 |
| 292 |
| |||||
Capital contributions from parent |
|
|
| 348 |
|
|
|
|
|
|
| 348 |
| |||||
Cash dividends declared |
|
|
|
|
| (175 | ) |
|
| (5 | ) | (180 | ) | |||||
Balance at December 31, 2009 |
| 40 |
| $ | 1,788 |
| $ | 1,407 |
| $ | (33 | ) | $ | 97 |
| $ | 3,259 |
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings Available for Common Shareholder |
|
|
|
|
| 290 |
|
|
| 14 |
| 304 |
| |||||
Deferred Cost of Employee Benefit Plans, net of tax $19 |
|
|
|
|
|
|
| 31 |
|
|
| 31 |
| |||||
Total Comprehensive Income |
|
|
|
|
| 290 |
| 31 |
| 14 |
| 335 |
| |||||
Capital contributions from parent |
|
|
| 146 |
|
|
|
|
|
|
| 146 |
| |||||
Cash dividends declared |
|
|
|
|
| (192 | ) |
|
| (7 | ) | (199 | ) | |||||
Balance at December 31, 2010 |
| 40 |
| $ | 1,934 |
| $ | 1,505 |
| $ | (2 | ) | $ | 104 |
| $ | 3,541 |
|
Comprehensive Income (Loss): |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings Available for Common Shareholder |
|
|
|
|
| 306 |
|
|
| 10 |
| 316 |
| |||||
Losses on Employee Benefit Plans, net of tax $- |
|
|
|
|
|
|
| (1 | ) |
|
| (1 | ) | |||||
Total Comprehensive Income (Loss) |
|
|
|
|
| 306 |
| (1 | ) | 10 |
| 315 |
| |||||
Capital contributions from parent |
|
|
| 107 |
|
|
|
|
|
|
| 107 |
| |||||
Cash dividends declared |
|
|
|
|
| (184 | ) |
|
| (6 | ) | (190 | ) | |||||
Balance at December 31, 2011 |
| 40 |
| $ | 2,041 |
| $ | 1,627 |
| $ | (3 | ) | $ | 108 |
| $ | 3,773 |
|
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. Jointly Owned Utility Plant Unit 1 New Units As of December 31, 2011 Percent owned 66.7 % 55.0 % Plant in service $ 1.0 billion — Accumulated depreciation $ 545.0 million — Construction work in progress $ 71.0 million $ 1.2 billion As of December 31, 2010 Percent owned 66.7 % 55.0 % Plant in service $ 1.0 billion — Accumulated depreciation $ 548.8 million — Construction work in progress $ 40.1 million $ 891.2 million 10. 2012. 2020. expense as incurred. 2012. subsequent hearings. See Note 2.1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESOrganization and Principles of ConsolidationSCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.The accompanying Consolidated Financial Statements reflect the accounts of SCE&G, Fuel Company and GENCO. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs), and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.GENCO owns a coal-fired electric generating station with a 605 megawatt net generating capacity (summer rating). GENCO’s electricity is sold, 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 $491 million)$476 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.Use of EstimatesThe preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.Utility PlantUtility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction,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. Consolidated SCE&G calculated AFC using average composite rates of 4.6%6.9% for 2011, 7.3%2013, 6.3% for 20102012 and 7.4%4.6% for 2009.2011. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.Consolidated SCE&G records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.90%2.94% in 2011, 2.84%2013, 2.91% in 20102012 and 2.95%2.90% in 2009.Consolidated 2011.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.119SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses areis included in the corresponding operating expenses on its income statement.As of December 31, 2013 2012 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.1 billion — $ 1.1 billion — Accumulated depreciation $ 566.9 million — $ 557.0 million — Construction work in progress $ 127.1 million $ 2.3 billion $ 113.6 million $ 1.8 billion SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0$5.4 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-yearone-year and five year-year escalation rates as required by the SCPSC.SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent For a discussion of the output ofwhen the New Units. As previously reported,Units are expected to be placed in service, and a description of SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation&G's agreement to acquire an additional 5% ownership in the New Units. Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units, and unanticipated rock conditions at the site. These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium. While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million. SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (seesee Note 2 to the consolidated financial statements), will be recoverable through rates.Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6$75.6 million at December 31, 20112013 and $77.9$92.9 million at December 31, 2010.Plant to be RetiredAs previously disclosed, in 2012 SCE&G identified a total of six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. As of December 31, 2013, three of these units had been retired and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.Major MaintenancePlanned 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 are classified as a regulatory asset or regulatory liability on the balance sheet (see Note 2). Other planned major maintenance is expensed when incurred.Through 2017, SCE&G is authorized to collect $18.4$18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the yearyears ended December 31, 2011,2013 and 2012, SCE&G incurred $11.5$18.1 million and $11.1 million, respectively, for turbine maintenance. Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage.apart. SCE&G accrued $1.2$1.2 million per month from July 2008January 2010 through July 2011December 2012 for its portion of the outages in the spring of 2011 and the fall of 2009 and the spring of 2011.2012. Total costs for the 20092011 outage were116$34.1 million$32.7 million,, of which SCE&G was responsible for $21.8 million.$22.7 million. Total costs for the 20112012 outage were $34.1$32.3 million, of which SCE&G was responsible for $22.7 million.$21.5 million. In July 2011,connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began accruing $1.2to accrue $1.4 million per month for its portion of the nuclear refueling planned foroutages that are scheduled to occur through the fallspring of 2012. SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.120Nuclear DecommissioningSCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0$696.8 million, stated in 2006 dollars.2012 dollars, pursuant an updated decommissioning cost study performed in 2012. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site wouldwill be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($($3.2 million pre-tax in each of 2011, 20102013, 2012 and 2009)2011) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.Cash and Cash EquivalentsConsolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills and notes.Accountbills.Accounts ReceivableAccounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.InventoryMaterials 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 and fuel oil. 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. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC.Income TaxesConsolidated SCE&G is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.Regulatory Assets and Regulatory LiabilitiesConsolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See(see Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.121Debt Premium, Discount and Expense, Unamortized Loss on Reacquired DebtConsolidated SCE&G records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.EnvironmentalEnvironmentalSCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debitsregulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.Income Statement PresentationIn its consolidated statements of income, Consolidated SCE&G presents the activitiesrevenues and expenses of its regulated businessesactivities (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).Revenue RecognitionConsolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $117.8$111.9 million at December 31, 20112013 and $123.4$129.0 million at December 31, 2010.Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during the next annual hearing.Customers subject to the PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. In addition, included in these deferred amounts are realized gains and losses incurred in SCE&G’s natural gas hedging program.SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers, and it will continue on a pilot basis unless modified or terminatedcustomers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC.Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Accordingly, no suchSuch taxes are not included in revenues or expenses in the statements of income.New Accounting MatterEffective for the first quarter of 2012, Consolidated SCE&G will adopt accounting guidance that revises how comprehensive income is presented in its financial statements. Consolidated SCE&G does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.118
Electric
SCE&G’s&G's retail electric rates are established in part by usinginclude 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. EffectiveIn April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a twelve month period beginning with the first billing cycle of May 2010,2012.
On July 15, 2010,April 3, 2014.
On July 15, 2010, the SCPSC issued an order approving the implementation by 2012.
| Year | Effective | Amount | ||
| 2013 | First billing cycle of May | $16.9 million | ||
| 2012 | First billing cycle of May | $19.6 million | ||
| 2011 | First billing cycle of June | $7.0 million | ||
May 2013 order previously described.
In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.
In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule sought by SCE&G that, reflected the removal of the contingency reserve andamong other matters, incorporated then identifiablethen-identifiable additional capital costs of $173.9$173.9 million (in (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011,.
On February 29,2007 dollars). The November 2012 SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporatesapproved additional identifiable capital costs of approximately $6
site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.
Year |
| Increase |
| Amount |
| |
2011 |
| 2.4 | % | $ | 52.8 million |
|
2010 |
| 2.3 | % | $ | 47.3 million |
|
2009 |
| 1.1 | % | $ | 22.5 million |
|
| Year | Increase | Amount | ||||
| 2013 | 2.90% | $ | 67.2 | million | ||
| 2012 | 2.30% | $ | 52.1 | million | ||
| 2011 | 2.40% | $ | 52.8 | million | ||
SCE&G
Year |
| Action |
| Amount |
| |||
2011 |
| 2.1 | % | Increase |
| $ | 8.6 million |
|
2010 |
| 2.1 | % | Decrease |
| $ | 10.4 million |
|
2009 |
| 2.5 | % | Increase |
| $ | 13.0 million |
|
| Year | Action | Amount | |||||||
| 2013 | No change | ||||||||
| 2012 | 2.10 | % | Increase | $ | 7.5 | million | |||
| 2011 | 2.10 | % | Increase | $ | 8.6 | million | |||
Regulatory Assets and Regulatory Liabilities
|
| December 31, |
| ||||
Millions of dollars |
| 2011 |
| 2010 |
| ||
Regulatory Assets: |
|
|
|
|
| ||
Accumulated deferred income taxes |
| $ | 238 |
| $ | 205 |
|
Under-collections-electric fuel adjustment clause |
| 28 |
| 25 |
| ||
Environmental remediation costs |
| 25 |
| 27 |
| ||
AROs and related funding |
| 301 |
| 284 |
| ||
Franchise agreements |
| 40 |
| 45 |
| ||
Deferred employee benefit plan costs |
| 348 |
| 288 |
| ||
Planned major maintenance |
| 6 |
| 6 |
| ||
Deferred losses on interest rate derivatives |
| 154 |
| 83 |
| ||
Deferred pollution control costs |
| 25 |
| 13 |
| ||
Other |
| 41 |
| 20 |
| ||
Total Regulatory Assets |
| $ | 1,206 |
| $ | 996 |
|
Regulatory Liabilities: |
|
|
|
|
| ||
Accumulated deferred income taxes |
| $ | 23 |
| $ | 26 |
|
Asset removal costs |
| 493 |
| 568 |
| ||
Storm damage reserve |
| 32 |
| 38 |
| ||
Deferred gains on interest rate derivatives |
| 24 |
| 26 |
| ||
Other |
| 3 |
| 4 |
| ||
Total Regulatory Liabilities |
| $ | 575 |
| $ | 662 |
|
| December 31, | ||||||||
| Millions of dollars | 2013 | 2012 | ||||||
| Regulatory Assets: | ||||||||
| Accumulated deferred income taxes | $ | 256 | $ | 248 | ||||
| Under-collections-electric fuel adjustment clause | 18 | 66 | ||||||
| Environmental remediation costs | 37 | 39 | ||||||
| AROs and related funding | 350 | 304 | ||||||
| Franchise agreements | 31 | 36 | ||||||
| Deferred employee benefit plan costs | 215 | 405 | ||||||
| Planned major maintenance | — | 6 | ||||||
| Deferred losses on interest rate derivatives | 124 | 151 | ||||||
| Deferred pollution control costs | 37 | 38 | ||||||
| Unrecovered Plant | 145 | 20 | ||||||
| DSM Programs | 51 | 27 | ||||||
| Other | 39 | 37 | ||||||
| Total Regulatory Assets | $ | 1,303 | $ | 1,377 | ||||
| Regulatory Liabilities: | ||||||||
| Accumulated deferred income taxes | $ | 19 | $ | 21 | ||||
| Asset removal costs | 495 | 507 | ||||||
| Storm damage reserve | 27 | 27 | ||||||
| Deferred gains on interest rate derivatives | 181 | 110 | ||||||
| Planned major maintenance | 10 | — | ||||||
| Total Regulatory Liabilities | $ | 732 | $ | 665 | ||||
Under-collections-electric
over periods exceeding
12 months.Planned major maintenance related to certain fossil fuelfossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5collects $18.4 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclearsuch equipment maintenance. Through December 31, 2012, nuclear refueling charges arewere accrued during each 18-month18-month refueling outage cycle as a component of cost of service.
In connection with the December 2012 rate order, effective January 1, 2013, SCE&G collects and accrues $16.8 million annually for nuclear-related refueling charges.
The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.
be recovered over periods not to exceed 24 months from date of deferral. See Rate Matters - Electric Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered lost revenue.
collection through rates indefinitely.
| Millions of Dollars | Deferred Employee Benefit Plans | |||
| Accumulated Other Comprehensive Loss as of January 1, 2012 | $ | (3 | ) | |
| Other comprehensive loss | (1 | ) | ||
| Accumulated Other Comprehensive Loss as of December 31, 2012 | (4 | ) | ||
| Other comprehensive income | 1 | |||
| Accumulated Other Comprehensive Loss as of December 31, 2013 | $ | (3 | ) | |
2012.
With respect to hydroelectric projects, the
122
4.LONG-TERM AND SHORT-TERM DEBT
|
|
|
| 2011 |
| 2010 |
| |||||||
Dollars in millions |
| Maturity |
| Balance |
| Rate |
| Balance |
| Rate |
| |||
First Mortgage Bonds (secured) |
| 2013 - 2041 |
| $ | 2,790 |
| 5.89 | % | $ | 2,560 |
| 6.03 | % | |
GENCO Notes (secured) |
| 2012 - 2024 |
| 247 |
| 5.86 | % | 262 |
| 5.91 | % | |||
Industrial and Pollution Control Bonds(a) |
| 2012 - 2038 |
| 194 |
| 4.48 | % | 228 |
| 4.63 | % | |||
Other |
| 2012 - 2027 |
| 22 |
|
|
| 24 |
|
|
| |||
Total debt |
|
|
| 3,253 |
|
|
| 3,074 |
|
|
| |||
Current maturities of long-term debt |
|
|
| (19 | ) |
|
| (23 | ) |
|
| |||
Unamortized discount |
|
|
| (12 | ) |
|
| (14 | ) |
|
| |||
Total long-term debt, net |
|
|
| $ | 3,222 |
|
|
| $ | 3,037 |
|
|
| |
| 2013 | 2012 | |||||||||||||||
| Dollars in millions | Maturity | Balance | Rate | Balance | Rate | |||||||||||
| First Mortgage Bonds (secured) | 2018 - 2042 | $ | 3,540 | 5.60 | % | $ | 3,290 | 5.66 | % | |||||||
| GENCO Notes (secured) | 2018 - 2024 | 233 | 5.89 | % | 240 | 5.87 | % | |||||||||
| Industrial and Pollution Control Bonds (a) | 2014 - 2038 | 158 | 3.83 | % | 161 | 4.32 | % | |||||||||
| Nuclear Fuel Financing | 2016 | 100 | 0.78 | % | — | — | ||||||||||
| Other | 2014 - 2027 | 16 | 2.26 | % | 21 | 1.62 | % | |||||||||
| Total debt | 4,047 | 3,712 | ||||||||||||||
| Current maturities of long-term debt | (48 | ) | (165 | ) | ||||||||||||
| Unamortized premium | 8 | 10 | ||||||||||||||
| Total long-term debt, net | $ | 4,007 | $ | 3,557 | ||||||||||||
Year |
| Millions of |
| |
2012 |
| $ | 19 |
|
2013 |
| 164 |
| |
2014 |
| 47 |
| |
2015 |
| 7 |
| |
2016 |
| 7 |
| |
| Year | Millions of dollars | ||
| 2014 | $ | 48 | |
| 2015 | 9 | ||
| 2016 | 109 | ||
| 2017 | 8 | ||
| 2018 | 718 | ||
outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2013, the Bond Ratio was
5.28.Millions of dollars |
| 2011 |
| 2010 |
| ||
Lines of credit: |
|
|
|
|
| ||
Committed long-term |
|
|
|
|
| ||
Total |
| $ | 1,100 |
| $ | 1,100 |
|
LOC advances |
| — |
| — |
| ||
Weighted average interest rate |
| — |
| — |
| ||
Outstanding commercial paper (270 or fewer days) |
| $ | 512 |
| $ | 381 |
|
Weighted average interest rate |
| .56 | % | .42 | % | ||
Letters of credit supported by an LOC |
| $ | .3 |
| $ | .3 |
|
Available |
| $ | 588 |
| $ | 719 |
|
| Millions of dollars | 2013 | 2012 | ||||||
| Lines of credit: | ||||||||
| Total committed long-term | $ | 1,400 | $ | 1,400 | ||||
| LOC advances | — | — | ||||||
| Weighted average interest rate | — | — | ||||||
| Outstanding commercial paper (270 or fewer days) | $ | 251 | $ | 449 | ||||
| Weighted average interest rate | 0.27 | % | 0.42 | % | ||||
| Letters of credit supported by an LOC | $ | 0.3 | $ | 0.3 | ||||
| Available | $ | 1,149 | $ | 951 | ||||
Finance LLC each provide 8%,8.9% and Deutsche Bank AG New York Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%6.3%. ThreeTwo other banks provide the remaining 6%. These bank credit facilities supportsupport. Consolidated SCE&G pays fees to the issuancebanks as compensation for maintaining the committed lines of commercial paper by SCE&G (including Fuel Company). When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).
credit. Such fees were not material in any period presented.
The Company
Such fees were not material in any period presented.
Total
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| |||
Current taxes: |
|
|
|
|
|
|
| |||
Federal |
| $ | 52 |
| $ | (56 | ) | $ | 60 |
|
State |
| 12 |
| (5 | ) | (9 | ) | |||
Total current taxes |
| 64 |
| (61 | ) | 51 |
| |||
Deferred taxes, net: |
|
|
|
| �� |
|
| |||
Federal |
| 98 |
| 207 |
| 75 |
| |||
State |
| 6 |
| 15 |
| 6 |
| |||
Total deferred taxes |
| 104 |
| 222 |
| 81 |
| |||
Investment tax credits: |
|
|
|
|
|
|
| |||
Deferred-state |
| — |
| — |
| 20 |
| |||
Amortization of amounts deferred—state |
| (25 | ) | (28 | ) | (9 | ) | |||
Amortization of amounts deferred—federal |
| (3 | ) | (3 | ) | (3 | ) | |||
Total investment tax credits |
| (28 | ) | (31 | ) | 8 |
| |||
Total income tax expense |
| $ | 140 |
| $ | 130 |
| $ | 140 |
|
| Millions of dollars | 2013 | 2012 | 2011 | |||||||||
| Current taxes: | ||||||||||||
| Federal | $ | 146 | $ | 91 | $ | 52 | ||||||
| State | 13 | 8 | 12 | |||||||||
| Total current taxes | 159 | 99 | 64 | |||||||||
| Deferred taxes, net: | ||||||||||||
| Federal | 25 | 62 | 98 | |||||||||
| State | 9 | 12 | 6 | |||||||||
| Total deferred taxes | 34 | 74 | 104 | |||||||||
| Investment tax credits: | ||||||||||||
| Amortization of amounts deferred—state | (1 | ) | (13 | ) | (25 | ) | ||||||
| Amortization of amounts deferred—federal | (3 | ) | (3 | ) | (3 | ) | ||||||
| Total investment tax credits | (4 | ) | (16 | ) | (28 | ) | ||||||
| Total income tax expense | $ | 189 | $ | 157 | $ | 140 | ||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| |||
Net income |
| $ | 306 |
| $ | 290 |
| $ | 281 |
|
Income tax expense |
| 140 |
| 130 |
| 140 |
| |||
Noncontrolling interest |
| 10 |
| 14 |
| 7 |
| |||
Total pre-tax income |
| $ | 456 |
| $ | 434 |
| $ | 428 |
|
Income taxes on above at statutory federal income tax rate |
| $ | 159 |
| $ | 152 |
| $ | 150 |
|
Increases (decreases) attributed to: |
|
|
|
|
|
|
| |||
Allowance for equity funds used during construction |
| (5 | ) | (8 | ) | (10 | ) | |||
State income taxes (less federal income tax effect) |
| 12 |
| 6 |
| 11 |
| |||
State investment tax credits (less federal income tax effect) |
| (16 | ) | (18 | ) | (6 | ) | |||
Amortization of federal investment tax credits |
| (3 | ) | (3 | ) | (3 | ) | |||
Domestic production activities deduction |
| (6 | ) | — |
| (4 | ) | |||
Other differences, net |
| (1 | ) | 1 |
| 2 |
| |||
Total income tax expense |
| $ | 140 |
| $ | 130 |
| $ | 140 |
|
| Millions of dollars | 2013 | 2012 | 2011 | |||||||||
| Net income | $ | 380 | $ | 341 | $ | 306 | ||||||
| Income tax expense | 189 | 157 | 140 | |||||||||
| Noncontrolling interest | 11 | 11 | 10 | |||||||||
| Total pre-tax income | $ | 580 | $ | 509 | $ | 456 | ||||||
| Income taxes on above at statutory federal income tax rate | $ | 203 | $ | 178 | $ | 159 | ||||||
| Increases (decreases) attributed to: | ||||||||||||
| State income taxes (less federal income tax effect) | 18 | 17 | 12 | |||||||||
| State investment tax credits (less federal income tax effect) | (5 | ) | (13 | ) | (16 | ) | ||||||
| Allowance for equity funds used during construction | (9 | ) | (7 | ) | (5 | ) | ||||||
| Amortization of federal investment tax credits | (3 | ) | (3 | ) | (3 | ) | ||||||
| Section 45 tax credits | (5 | ) | (5 | ) | (2 | ) | ||||||
| Domestic production activities deduction | (11 | ) | (9 | ) | (6 | ) | ||||||
| Other differences, net | 1 | (1 | ) | 1 | ||||||||
| Total income tax expense | $ | 189 | $ | 157 | $ | 140 | ||||||
130
Millions of dollars |
| 2011 |
| 2010 |
| ||
Deferred tax assets: |
|
|
|
|
| ||
Nondeductible reserves |
| $ | 82 |
| $ | 85 |
|
Nuclear decommissioning |
| 47 |
| 45 |
| ||
Unamortized investment tax credits |
| 29 |
| 40 |
| ||
Deferred compensation |
| 7 |
| 8 |
| ||
Unbilled revenue |
| 19 |
| 19 |
| ||
Other |
| 12 |
| 5 |
| ||
Total deferred tax assets |
| 196 |
| 202 |
| ||
Deferred tax liabilities: |
|
|
|
|
| ||
Property, plant and equipment |
| 1,324 |
| 1,205 |
| ||
Pension plan income |
| 28 |
| 45 |
| ||
Deferred employee benefit plan costs |
| 110 |
| 91 |
| ||
Deferred fuel costs |
| 48 |
| 42 |
| ||
Other |
| 49 |
| 44 |
| ||
Total deferred tax liabilities |
| 1,559 |
| 1,427 |
| ||
Net deferred tax liability |
| $ | 1,363 |
| $ | 1,225 |
|
| Millions of dollars | 2013 | 2012 | ||||||
| Deferred tax assets: | ||||||||
| Nondeductible accruals | $ | 17 | $ | 73 | ||||
| Asset retirement obligation, including nuclear decommissioning | 209 | 204 | ||||||
| Unamortized investment tax credits | 19 | 21 | ||||||
| Unbilled revenue | — | 14 | ||||||
| Regulatory liability, net gain on interest rate derivative contracts settlement | 27 | — | ||||||
| Other | 11 | 13 | ||||||
| Total deferred tax assets | 283 | 325 | ||||||
| Deferred tax liabilities: | ||||||||
| Property, plant and equipment | $ | 1,494 | $ | 1,461 | ||||
| Regulatory asset-asset retirement obligation | 114 | 107 | ||||||
| Deferred employee benefit plan costs | 54 | 127 | ||||||
| Deferred fuel costs | 26 | 49 | ||||||
| Regulatory asset, unrecovered plant | 55 | 7 | ||||||
| Other | 62 | 53 | ||||||
| Total deferred tax liabilities | 1,805 | 1,804 | ||||||
| Net deferred tax liability | $ | 1,522 | $ | 1,479 | ||||
In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, SCE&G revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.
2009.
Millions of dollars |
| 2011 |
| 2010 |
| ||
Unrecognized tax benefits, January 1 |
| $ | 36 |
| — |
| |
Gross increases-tax positions in prior period |
| 5 |
| — |
| ||
Gross decreases-tax positions in prior period |
| (8 | ) | — |
| ||
Gross increases-current period tax positions |
| 5 |
| $ | 36 |
| |
Settlements |
| — |
| — |
| ||
Lapse of statute of limitations |
| — |
| — |
| ||
Unrecognized tax benefits, December 31 |
| $ | 38 |
| $ | 36 |
|
| Millions of dollars | 2013 | 2012 | 2011 | |||||||||
| Unrecognized tax benefits, January 1 | — | $ | 38 | $ | 36 | |||||||
| Gross increases-uncertain tax positions in prior period | — | — | 5 | |||||||||
| Gross decreases-uncertain tax positions in prior period | — | (38 | ) | (8 | ) | |||||||
| Gross increases-current period uncertain tax positions | $ | 3 | — | 5 | ||||||||
| Settlements | — | — | — | |||||||||
| Lapse of statute of limitations | — | — | — | |||||||||
| Unrecognized tax benefits, December 31 | $ | 3 | $ | — | $ | 38 | ||||||
the Consolidated SCE&G’s tax positions have occurred through December 31, 2013.
125position.
expense. flow statement purposes. The fair value of Fair Values of Derivative Instruments Asset Derivatives Liability Derivatives Millions of dollars Balance Sheet Fair Balance Sheet Fair As of December 31, 2011 Derivatives designated as hedging instruments Interest rate contracts Other current assets $ 1 Other current liabilities $ 2 Other deferred credits 75 Total $ 1 $ 77 As of December 31, 2010 Derivatives designated as hedging instruments Interest rate contracts Other deferred debits $ 4 Other current liabilities $ 34 Other deferred credits 1 Total $ 4 $ 35 Derivatives not designated as hedging instruments Commodity contracts Prepayments and other $ 1 Derivatives in Cash Flow Hedging Relationships Gain or (Loss) Deferred Gain or (Loss) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2011 Interest rate contracts $ (76 ) Interest expense $ (3 ) Year Ended December 31, 2010 Interest rate contracts $ (36 ) Interest expense $ (2 ) Year Ended December 31, 2009 Interest rate contracts $ 42 Interest expense $ (3 ) Derivatives Not Designated as Hedging Instruments Gain or (Loss) Recognized in Income Millions of dollars Location Amount Year Ended December 31, 2011 Commodity contracts Gas purchased for resale $ (2 ) Year Ended December 31, 2010 Commodity contracts Gas purchased for resale $ (3 ) Year Ended December 31, 2009 Commodity contracts Gas purchased for resale $ (16 ) $50 million offset revenue reductions as previously described herein and in Note 2. Fair Value Measurements Using Millions of dollars Quoted Prices in Active Significant Other As of December 31, 2011 Assets-Interest rate contracts — $ 1 Liabilities-Interest rate contracts — 77 As of December 31, 2010 Assets-Interest rate contracts — $ 4 Commodity contracts $ 1 — Liabilities-Interest rate contracts — 35 December 31, 2011 December 31, 2010 Millions of dollars Carrying Estimated Carrying Estimated Long-term debt $ 3,241.5 $ 3,920.3 $ 3,059.7 $ 3,321.8 6.DERIVATIVE FINANCIAL INSTRUMENTSConsolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statementits statements of financial position and measures those instruments at fair value. Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by Consolidated SCE&G. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries, including Consolidated SCE&G. The Risk Management Committee, which is comprised of certain officers, including the Consolidated SCE&G’s Risk Management Officer and senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to the Board’sAudit Committee's attention anysignificant 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 DerivativesSCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions. Cash settlement of commodity derivatives are classified as an operating activity in the consolidated statements of cash flows.SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. These derivative financial instruments are not designated as hedges for accounting purposes.Interest Rate SwapsConsolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements thatagreements. Pursuant to regulatory orders issued in 2013, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges. Thehedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, be amortized to interest expense or applied as otherwise directed by the SCPSC. As discussed in Note 2, in these orders, the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013. Prior to this regulatory authorization, such interest rate derivatives were designated as cash flow hedges, and only the effective portions of changes in fair value and payments made or received upon termination of such agreements arewere recorded in regulatory assets or regulatory liabilities. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions arewere recognized in income.Cash payments made or received upon terminationsettlement of these financial instruments are classified as an investing activity in the consolidated statements ofactivities for cash flows.The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the consolidated statements of cash flows.Quantitative Disclosures Related to DerivativesSCE&G was party to natural gas derivative contracts for 2,490,000 DT and 2,460,000 DT at December 31, 2011 and 2010, respectively. Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $471.4$36.4 million and $421.4$971.4 million at December 31, 2013 and 2012, respectively. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion and $0.0 million at December 31, 20112013 and 2010,2012, respectively.132 energy-related derivatives and interest rate derivatives was reflected in the consolidated balance sheet as follows:
Location(a)
Value
Location(a)
Value(a)Asset derivatives represent unrealized gains to Consolidated SCE&G, and liability derivatives represent unrealized losses. In Consolidated SCE&G’s consolidated balance sheet, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis. Fair Values of Derivative Instruments Asset Derivatives Liability Derivatives Millions of dollars Balance SheetLocation FairValue Balance SheetLocation FairValueAs of December 31, 2013 Derivatives designated as hedging instruments Interest rate contracts Other current liabilities $ 1 Total $ 1 Derivatives not designated as hedging instruments Interest rate contracts Prepayments and other $ 13 Other current liabilities $ 1 Other deferred debits and other assets 19 Total $ 32 $ 1 As of December 31, 2012 Derivatives designated as hedging instruments Interest rate contracts Prepayments and other $ 42 Other current liabilities $ 66 Other deferred debits and other assets 31 Other deferred credits and other liabilities 9 Total $ 73 $ 75 The effect of derivative instruments on the consolidated statement of income is as follows:
in Regulatory Accounts
Reclassified from
Deferred Accounts into Income
(Effective Portion)Derivatives in Cash Flow Hedging Relationships Gain or (Loss) Deferredin Regulatory Accounts Loss Reclassified fromDeferred Accounts into Income(Effective Portion)Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2013 Interest rate contracts $ 106 Interest expense $ (3 ) Year Ended December 31, 2012 Interest rate contracts $ 84 Interest expense $ (3 ) Year Ended December 31, 2011 Interest rate contracts $ (76 ) Interest expense $ (3 ) Hedge IneffectivenessOther gains (losses)losses recognized in income representing ineffectiveness on interest rate hedge ineffectivenesshedges designated as cash flow hedges were $(1.1)insignificant in 2013 and 2012 and were $(1.1) million, net of tax, in 2011 and were insignificant in 2010. These amounts are recorded within interest expense on the statement of income.Derivatives Not Designated as Hedging Instruments Loss Recognized in Income Year Ended December 31, Millions of dollars Location 2013 2012 2011 Commodity contracts Gas purchased for resale — $ (1 ) $ (2 ) 133 Gain Deferredin Regulatory Accounts Gain Reclassified fromDeferred Accounts into IncomeMillions of dollars Location Amount Year Ended December 31, 2013 Interest rate contracts $ 39 Other income $ 50 Year Ended December 31, 2012 Interest rate contracts — — Year Ended December 31, 2011 Interest rate contracts — — The gains reclassified to other income of ContentsCredit Risk ConsiderationsConsolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. Consolidated SCE&G uses standardized master agreements which generally include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require collateralConsolidated SCE&G to be providedprovide collateral upon the occurrence of specific events, primarily credit rating downgrades. As of December 31, 20112013 and 2010,2012, Consolidated SCE&G hashad posted $45.0$1.5 million and $0$35.2 million, respectively, of collateral related to derivatives with contingent provisions that arewere in a net liability position. Collateral related to the positions expected to close in the next 12 months are recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions are recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments werehad been fully triggered as of December 31, 20112013 and 2010,2012, Consolidated SCE&G would behave been required to post an additional $31.7$0.0 million and $34.9$22.7 million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 20112013 and 2010,2012, are $76.7$1.0 million and $34.9$57.9 million, respectively.In addition, as of December 31, 2013 and December 31, 2012, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2013 and December 31, 2012, Consolidated SCE&G could request $31.7 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2013 and December 31, 2012 is $31.7 million and $32.1 million, respectively.134Information related to Consolidated SCE&G's offsetting derivative assets follows: Gross Amounts Not Offset in the Statement of Financial Position Millions of dollars Gross Amounts of Recognized Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Received Net Amount As of December 31, 2013 Interest rate $ 32 — $ 32 $ (1 ) — $ 31 Balance sheet location Prepayments and other $ 13 Other deferred debits and other assets 19 Total $ 32 As of December 31, 2012 Interest rate $ 73 — $ 73 $ (17 ) — $ 56 Balance sheet location Prepayments and other $ 42 Other deferred debits and other assets 31 Total $ 73 Information related to Consolidated SCE&G's offsetting derivative liabilities follows: Gross Amounts Not Offset in the Statement of Financial Position Millions of dollars Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Posted Net Amount As of December 31, 2013 Interest rate $ 2 — $ 2 $ (1 ) $ 1 $ — Balance sheet location Other current liabilities $ 2 Total $ 2 As of December 31, 2012 Interest rate $ 75 — $ 75 $ (17 ) $ 35 $ 23 Balance sheet location Other current liabilities $ 66 Other deferred credits and other liabilities 9 Total $ 75 1357.FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVESSCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value Level 2 measurements and the level within the fair value hierarchy in which the measurements fall, were as follows:
Markets for Identical Assets
(Level 1)
Observable Inputs
(Level 2) As of December 31, 2013 As of December 31, 2012 Millions of dollars Level 2 Level 2 Assets-Interest rate contracts $ 32 $ 73 Liabilities-Interest rate contracts 2 75 There were no Level 1 or Level 3 fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition,presented and there were no transfers of fair value amounts into or out of Levels 1, and 2 or 3 during any periodthe periods presented.Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 20112013 and December 31, 20102012 were as follows:
Amount
Fair
Value
Amount
Fair
Value As of December 31, 2013 As of December 31, 2012 Millions of dollars CarryingAmount EstimatedFair Value CarryingAmount EstimatedFair ValueLong-term debt $ 4,054.9 $ 4,433.0 $ 3,722.0 $ 4,543.1 Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations.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. Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data. Early settlement of long-term debt may not be possible or may not be considered prudent.Potential taxes and other expenses that wouldCarrying 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 incurred in an actual sale or settlement have not been considered.128Level 2.
8.EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
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.
|
| Pension Benefits |
| Other |
| ||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Benefit obligation, January 1 |
| $ | 687.8 |
| $ | 667.4 |
| $ | 171.5 |
| $ | 171.4 |
|
Service cost |
| 14.7 |
| 14.0 |
| 3.4 |
| 3.2 |
| ||||
Interest cost |
| 37.0 |
| 41.2 |
| 9.6 |
| 9.3 |
| ||||
Plan participants’ contributions |
| — |
| — |
| 2.5 |
| 2.4 |
| ||||
Actuarial (gain) loss |
| 2.6 |
| (0.6 | ) | 5.6 |
| (1.1 | ) | ||||
Benefits paid |
| (37.1 | ) | (34.2 | ) | (11.2 | ) | (11.4 | ) | ||||
Amounts funded to parent |
| — |
| — |
| (3.0 | ) | (2.3 | ) | ||||
Benefit obligation, December 31 |
| $ | 705.0 |
| $ | 687.8 |
| $ | 178.4 |
| $ | 171.5 |
|
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Benefit obligation, January 1 | $ | 788.4 | $ | 705.0 | $ | 206.0 | $ | 178.4 | ||||||||
| Service cost | 17.6 | 15.7 | 4.6 | 3.7 | ||||||||||||
| Interest cost | 32.6 | 36.4 | 8.7 | 9.4 | ||||||||||||
| Plan participants’ contributions | — | — | 2.0 | 2.3 | ||||||||||||
| Actuarial (gain) loss | (70.7 | ) | 80.3 | (27.3 | ) | 26.2 | ||||||||||
| Benefits paid | (50.6 | ) | (49.0 | ) | (9.3 | ) | (10.8 | ) | ||||||||
| Curtailment | (21.6 | ) | — | — | — | |||||||||||
| Amounts funded to parent | — | — | (3.0 | ) | (3.2 | ) | ||||||||||
| Benefit obligation, December 31 | $ | 695.7 | $ | 788.4 | $ | 181.7 | $ | 206.0 | ||||||||
|
| Pension |
| Other |
| ||||
|
| 2011 |
| 2010 |
| 2011 |
| 2010 |
|
Annual discount rate used to determine benefit obligation |
| 5.25 | % | 5.56 | % | 5.35 | % | 5.72 | % |
Assumed annual rate of future salary increases for projected benefit obligation |
| 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % |
An 8.2%
| Pension Benefits | Other Postretirement Benefits | |||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||
| Annual discount rate used to determine benefit obligation | 5.03 | % | 4.10 | % | 5.19 | % | 4.19 | % | ||||
| Assumed annual rate of future salary increases for projected benefit obligation | 3.00 | % | 3.75 | % | 3.75 | % | 3.75 | % | ||||
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Fair value of plan assets | $ | 792.1 | $ | 732.0 | — | — | ||||||||||
| Benefit obligation | 695.7 | 788.4 | $ | 181.7 | $ | 206.0 | ||||||||||
| Funded status | $ | 96.4 | $ | (56.4 | ) | $ | (181.7 | ) | $ | (206.0 | ) | |||||
Funded Status
Millions of Dollars |
| Pension Benefits |
| Other |
| ||||||||
December 31, |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Fair value of plan assets |
| $ | 695.3 |
| $ | 745.2 |
| — |
| — |
| ||
Benefit obligations |
| 705.0 |
| 687.8 |
| $ | 178.4 |
| $ | 171.5 |
| ||
Funded status (liability) |
| $ | (9.7 | ) | $ | 57.4 |
| $ | (178.4 | ) | $ | (171.5 | ) |
Millions of Dollars |
| Pension Benefits |
| Other |
| ||||||||
December 31, |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Noncurrent asset |
| — |
| $ | 57.4 |
| — |
| — |
| |||
Current liability |
| — |
| — |
| $ | (8.3 | ) | $ | (8.9 | ) | ||
Noncurrent liability |
| $ | (9.7 | ) | — |
| (170.1 | ) | (162.6 | ) | |||
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Current liability | — | — | $ | (7.8 | ) | $ | (8.5 | ) | ||||||||
| Noncurrent asset | $ | 96.4 | — | — | — | |||||||||||
| Noncurrent liability | — | $ | (56.4 | ) | (173.9 | ) | (197.5 | ) | ||||||||
Millions of Dollars |
| Pension |
| Other |
| ||||||||
December 31, |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| ||||
Net actuarial loss |
| $ | 2.4 |
| $ | 1.8 |
| $ | 0.4 |
| $ | 0.3 |
|
Prior service cost |
| 0.3 |
| 0.4 |
| 0.1 |
| 0.1 |
| ||||
Total |
| $ | 2.7 |
| $ | 2.2 |
| $ | 0.5 |
| $ | 0.4 |
|
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net actuarial loss | $ | 1.8 | $ | 2.7 | $ | 0.6 | $ | 1.1 | ||||||||
| Prior service cost | 0.2 | 0.2 | — | — | ||||||||||||
| Total | $ | 2.0 | $ | 2.9 | $ | 0.6 | $ | 1.1 | ||||||||
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| December 31, | 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net actuarial loss | $ | 107.7 | $ | 257.5 | $ | 20.1 | $ | 46.7 | ||||||||
| Prior service cost | 11.1 | 23.3 | 0.7 | 1.2 | ||||||||||||
| Transition obligation | — | — | — | 0.1 | ||||||||||||
| Total | $ | 118.8 | $ | 280.8 | $ | 20.8 | $ | 48.0 | ||||||||
|
| Pension Benefits |
| ||||
Millions of dollars |
| 2011 |
| 2010 |
| ||
Fair value of plan assets, January 1 |
| $ | 745.2 |
| $ | 660.7 |
|
Actual return on plan assets |
| (12.8 | ) | 118.7 |
| ||
Benefits paid |
| (37.1 | ) | (34.2 | ) | ||
Fair value of plan assets, December 31 |
| $ | 695.3 |
| $ | 745.2 |
|
| Pension Benefits | ||||||||
| Millions of dollars | 2013 | 2012 | ||||||
| Fair value of plan assets, January 1 | $ | 732.0 | $ | 695.3 | ||||
| Actual return on plan assets | 110.7 | 85.7 | ||||||
| Benefits paid | (50.6 | ) | (49.0 | ) | ||||
| Fair value of plan assets, December 31 | $ | 792.1 | $ | 732.0 | ||||
engaging in speculative trading are also prohibited.
|
| Percentage of Plan Assets |
| ||||
|
| Target |
| At |
| ||
Asset Category |
| 2012 |
| 2011 |
| 2010 |
|
Equity Securities |
| 65 | % | 65 | % | 68 | % |
Debt Securities |
| 35 | % | 35 | % | 32 | % |
| Percentage of Plan Assets | |||||||||
Target Allocation | At December 31, | ||||||||
| Asset Category | 2014 | 2013 | 2012 | ||||||
| Equity Securities | 58 | % | 59 | % | 66 | % | |||
| Fixed Income | 33 | % | 32 | % | 25 | % | |||
| Hedge Funds | 9 | % | 9 | % | 9 | % | |||
Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment policy adopted for 2014.
|
|
|
| Fair Value Measurements at Reporting Date Using |
| ||||||||
Millions of dollars |
| December 31, |
| Quoted Market Prices |
| Significant |
| Significant |
| ||||
December 31, 2011 |
|
|
|
|
|
|
|
|
| ||||
Common stock |
| $ | 298 |
| $ | 298 |
|
|
|
|
| ||
Preferred stock |
| 1 |
| 1 |
|
|
|
|
| ||||
Mutual funds |
| 169 |
| 19 |
| $ | 150 |
|
|
| |||
Short-term investment vehicles |
| 21 |
|
|
| 21 |
|
|
| ||||
Government agency securities |
| 29 |
|
|
| 29 |
|
|
| ||||
Corporate debt securities |
| 47 |
|
|
| 47 |
|
|
| ||||
Loans secured by mortgages |
| 11 |
|
|
| 11 |
|
|
| ||||
Municipals |
| 4 |
|
|
| 4 |
|
|
| ||||
Common collective trusts |
| 34 |
|
|
| 34 |
|
|
| ||||
Limited partnerships |
| 21 |
|
|
| 21 |
|
|
| ||||
Multi-strategy hedge funds |
| 60 |
|
|
|
|
| $ | 60 |
| |||
|
| $ | 695 |
| $ | 318 |
| $ | 317 |
| $ | 60 |
|
December 31, 2010 |
|
|
|
|
|
|
|
|
| ||||
Common stock |
| $ | 331 |
| $ | 331 |
|
|
|
|
| ||
Mutual funds |
| 187 |
| 22 |
| $ | 165 |
|
|
| |||
Short-term investment vehicles |
| 17 |
|
|
| 17 |
|
|
| ||||
Government agency securities |
| 47 |
|
|
| 47 |
|
|
| ||||
Corporate debt securities |
| 46 |
|
|
| 46 |
|
|
| ||||
Loans secured by mortgages |
| 8 |
|
|
| 8 |
|
|
| ||||
Municipals |
| 3 |
|
|
| 3 |
|
|
| ||||
Common collective trusts |
| 41 |
|
|
| 41 |
|
|
| ||||
Limited partnerships |
| 24 |
| 1 |
| 23 |
|
|
| ||||
Multi-strategy hedge funds |
| 41 |
|
|
|
|
| $ | 41 |
| |||
|
| $ | 745 |
| $ | 354 |
| $ | 350 |
| $ | 41 |
|
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||||||||||||||||||
| Millions of dollars | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| December 31, 2013 | December 31, 2012 | |||||||||||||||||||||||||||||||
| Common stock | $ | 302 | $ | 302 | $ | 292 | $ | 292 | ||||||||||||||||||||||||
| Preferred stock | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||||||
| Mutual funds | 278 | 18 | $ | 260 | 226 | 12 | $ | 214 | ||||||||||||||||||||||||
| Short-term investment vehicles | 18 | 18 | 18 | 18 | ||||||||||||||||||||||||||||
| US Treasury securities | 30 | 30 | 38 | 38 | ||||||||||||||||||||||||||||
| Corporate debt securities | 48 | 48 | 52 | 52 | ||||||||||||||||||||||||||||
| Loans secured by mortgages | 11 | 11 | 10 | 10 | ||||||||||||||||||||||||||||
| Municipals | 3 | 3 | 4 | 4 | ||||||||||||||||||||||||||||
| Limited partnerships | 32 | 1 | 31 | 27 | 1 | 26 | ||||||||||||||||||||||||||
| Multi-strategy hedge funds | 69 | $ | 69 | 64 | $ | 64 | ||||||||||||||||||||||||||
| $ | 792 | $ | 322 | $ | 401 | $ | 69 | $ | 732 | $ | 306 | $ | 362 | $ | 64 | |||||||||||||||||
TableThere were no transfers of Contents
fair value amounts into or out of Levels 1, 2 or 3 during 2013 or 2012.
|
| Fair Value |
| ||||
Millions of dollars |
| 2011 |
| 2010 |
| ||
Beginning Balance |
| $ | 41 |
| $ | 12 |
|
Unrealized gains (losses) included in changes in net assets |
| (1 | ) | 2 |
| ||
Purchases, issuances, and settlements |
| 20 |
| 27 |
| ||
Transfers in or out of Level 3 |
| — |
| — |
| ||
Ending Balance |
| $ | 60 |
| $ | 41 |
|
Fair Value Measurements Level 3 | ||||||||
| Millions of dollars | 2013 | 2012 | ||||||
| Beginning Balance | $ | 64 | $ | 60 | ||||
| Unrealized gains included in changes in net assets | 5 | 4 | ||||||
| Purchases, issuances, and settlements | — | — | ||||||
| Transfers in or out of Level 3 | — | — | ||||||
| Ending Balance | $ | 69 | $ | 64 | ||||
|
|
|
| Other Postretirement Benefits* |
| |||||
Millions of dollars |
| Pension Benefits |
| Excluding Medicare |
| Including Medicare |
| |||
2012 |
| $ | 73.4 |
| $ | 8.7 |
| $ | 8.4 |
|
2013 |
| 66.8 |
| 9.2 |
| 9.0 |
| |||
2014 |
| 61.8 |
| 9.9 |
| 9.7 |
| |||
2015 |
| 63.3 |
| 10.5 |
| 10.2 |
| |||
2016 |
| 65.5 |
| 11.0 |
| 10.8 |
| |||
2017 - 2021 |
| 315.5 |
| 61.5 |
| 60.5 |
| |||
*Net of participant contributions
| Millions of dollars | Pension Benefits | Other Postretirement Benefits | ||||||
| 2014 | $ | 61.5 | $ | 9.3 | ||||
| 2015 | 61.2 | 10.0 | ||||||
| 2016 | 63.8 | 10.6 | ||||||
| 2017 | 65.8 | 11.1 | ||||||
| 2018 | 66.1 | 11.6 | ||||||
| 2019 - 2023 | 338.4 | 65.1 | ||||||
Net Periodic Benefit Cost (Income)
|
| Pension Benefits |
| Other Postretirement |
| ||||||||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| 2011 |
| 2010 |
| 2009 |
| ||||||
Service cost |
| $ | 14.7 |
| $ | 14.0 |
| $ | 11.9 |
| $ | 3.4 |
| $ | 3.2 |
| $ | 2.8 |
|
Interest cost |
| 37.0 |
| 41.2 |
| 42.0 |
| 9.6 |
| 9.3 |
| 9.5 |
| ||||||
Expected return on assets |
| (54.2 | ) | (58.0 | ) | (48.2 | ) | n/a |
| n/a |
| n/a |
| ||||||
Prior service cost amortization |
| 6.0 |
| 6.6 |
| 6.6 |
| 0.8 |
| 0.8 |
| 0.8 |
| ||||||
Amortization of actuarial losses |
| 10.4 |
| 15.1 |
| 22.3 |
| 0.3 |
| — |
| — |
| ||||||
Transition amount amortization |
| — |
| — |
| — |
| (0.1 | ) | (0.1 | ) | (0.1 | ) | ||||||
Net periodic benefit cost |
| $ | 13.9 |
| $ | 18.9 |
| $ | 34.6 |
| $ | 14.0 |
| $ | 13.2 |
| $ | 13.0 |
|
In February 2009,
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| Service cost | $ | 17.6 | $ | 15.7 | $ | 14.7 | $ | 4.6 | $ | 3.7 | $ | 3.4 | ||||||||||||
| Interest cost | 32.6 | 36.4 | 37.0 | 8.7 | 9.4 | 9.6 | ||||||||||||||||||
| Expected return on assets | (51.9 | ) | (50.4 | ) | (54.2 | ) | n/a | n/a | n/a | |||||||||||||||
| Prior service cost amortization | 5.0 | 6.0 | 6.0 | 0.6 | 0.7 | 0.8 | ||||||||||||||||||
| Amortization of actuarial losses | 14.3 | 15.6 | 10.4 | 2.6 | 1.1 | 0.3 | ||||||||||||||||||
| Curtailment | 8.4 | — | — | — | — | — | ||||||||||||||||||
| Transition obligation amortization | — | — | — | — | — | (0.1 | ) | |||||||||||||||||
| Net periodic benefit cost | $ | 26.0 | $ | 23.3 | $ | 13.9 | $ | 16.5 | $ | 14.9 | $ | 14.0 | ||||||||||||
gas operations through cost of service rates (see Note 2).
|
| Pension Benefits |
| Other Postretirement |
| ||||||||||||||
Millions of dollars |
| 2011 |
| 2010 |
| 2009 |
| 2011 |
| 2010 |
| 2009 |
| ||||||
Current year actuarial (gain)/loss |
| $ | 0.7 |
| $ | (28.9 | ) | $ | (9.8 | ) | $ | 0.1 |
| $ | — |
| $ | 0.1 |
|
Amortization of actuarial losses |
| (0.1 | ) | (1.8 | ) | (3.6 | ) | — |
| — |
| — |
| ||||||
Amortization of prior service cost |
| (0.1 | ) | — |
| — |
| — |
| — |
| — |
| ||||||
Prior service cost OCI adjustment |
| — |
| 0.4 |
| — |
| — |
| — |
| — |
| ||||||
Amortization of transition obligation |
| — |
| — |
| — |
| — |
| (0.1 | ) | — |
| ||||||
Total recognized in other comprehensive income |
| $ | 0.5 |
| $ | (30.3 | ) | $ | (13.4 | ) | $ | 0.1 |
| $ | (0.1 | ) | $ | 0.1 |
|
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||||
| Current year actuarial (gain) loss | $ | (0.8 | ) | $ | 0.4 | $ | 0.7 | $ | (0.4 | ) | $ | 0.7 | — | $ | 0.1 | |||||||||||
| Amortization of actuarial losses | (0.1 | ) | (0.1 | ) | (0.1 | ) | (0.1 | ) | — | — | — | |||||||||||||||
| Amortization of prior service cost | — | (0.1 | ) | — | (0.1 | ) | — | (0.1 | ) | — | — | |||||||||||||||
| Prior service cost (credit) | — | — | 400,000 | — | — | — | — | — | ||||||||||||||||||
| Amortization of transition obligation | — | — | — | — | — | — | — | |||||||||||||||||||
| Total recognized in other comprehensive income (loss) | $ | (0.9 | ) | $ | 0.2 | 400,000 | $ | 0.5 | $ | (0.5 | ) | $ | 0.6 | $ | 0.1 | |||||||||||
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||
| Millions of dollars | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||||
| Current year actuarial (gain) loss | $ | (137.1 | ) | $ | 37.9 | $ | 61.8 | $ | (24.4 | ) | $ | 25.7 | — | $ | 5.0 | |||||||||||
| Amortization of actuarial losses | (12.7 | ) | (14.0 | ) | (9.3 | ) | (2.2 | ) | (1.0 | ) | — | (0.2 | ) | |||||||||||||
| Amortization of prior service cost | (4.5 | ) | (5.7 | ) | — | (5.5 | ) | (0.5 | ) | (0.7 | ) | — | (0.7 | ) | ||||||||||||
| Prior service cost (credit) | (7.7 | ) | — | 400,000 | — | — | — | — | — | |||||||||||||||||
| Amortization of transition obligation | — | — | — | — | (0.1 | ) | (0.2 | ) | (0.2 | ) | ||||||||||||||||
| Total recognized in regulatory assets | $ | (162.0 | ) | $ | 18.2 | $ | 47.0 | $ | (27.2 | ) | $ | 23.8 | $ | 3.9 | ||||||||||||
|
| Pension Benefits |
| Other Postretirement |
| |||||||||
|
| 2011 |
| 2010 |
| 2009 |
| 2011 |
| 2010 |
| 2009 |
| |
Discount rate |
| 5.56 | % | 5.75 | % | 6.45 | % | $ | 5.72 | % | 5.90 | % | 6.45 | % |
Expected return on plan assets |
| 8.25 | % | 8.50 | % | 8.50 | % | n/a |
| n/a |
| n/a |
| |
Rate of compensation increase |
| 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | |
Health care cost trend rate |
| n/a |
| n/a |
| n/a |
| 8.00 | % | 8.50 | % | 8.00 | % | |
Ultimate health care cost trend rate |
| n/a |
| n/a |
| n/a |
| 5.00 | % | 5.00 | % | 5.00 | % | |
Year achieved |
| n/a |
| n/a |
| n/a |
| 2017 |
| 2017 |
| 2015 |
| |
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||
| 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||
| Discount rate | 4.10%/5.07% | 5.25 | % | 5.56 | % | 4.19 | % | 5.35 | % | 5.72 | % | |||||||
| Expected return on plan assets | 8.00 | % | 8.25 | % | 8.25 | % | n/a | n/a | n/a | |||||||||
| Rate of compensation increase | 3.75%/3.00% | 4.00 | % | 4.00 | % | 3.75 | % | 4.00 | % | 4.00 | % | |||||||
| Health care cost trend rate | n/a | n/a | n/a | 7.80 | % | 8.20 | % | 8.00 | % | |||||||||
| Ultimate health care cost trend rate | n/a | n/a | n/a | 5.00 | % | 5.00 | % | 5.00 | % | |||||||||
| Year achieved | n/a | n/a | n/a | 2020 | 2020 | 2017 | ||||||||||||
Millions of Dollars |
| Pension |
| Other |
| |
Actuarial loss |
| $ | 0.1 |
| — |
|
Prior service cost |
| 0.1 |
| — |
| |
Total |
| $ | 0.2 |
| — |
|
| Millions of Dollars | Pension Benefits | Other Postretirement Benefits | ||||||
| Actuarial loss | $ | 3.7 | $ | 0.3 | ||||
| Prior service cost | 3.1 | 0.3 | ||||||
| Total | $ | 6.8 | $ | 0.6 | ||||
Other postretirement benefit costs are subject to annual per capita limits pursuant to planthe 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 less than $100,000.
not significant.
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.
2011.
2011.
Ins
Nonvested Shares |
| Shares |
| Weighted Average |
| |
Nonvested at January 1, 2009 |
| 74,588 |
| $ | 37.33 |
|
Forfeited |
| (2,399 | ) | 37.33 |
| |
Nonvested at December 31, 2009 |
| 72,189 |
| 37.33 |
| |
Vested |
| (72,189 |
| 37.33 |
| |
Nonvested at December 31, 2010 |
| — |
|
|
| |
Nonvested shares were granted at a price corresponding to the opening price of SCANA common stock on the date of the grant. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized. SCE&G expensed compensation costs for nonvested shares of $0.1 million in each of 2010operations, cash flows and 2009. Tax benefits and capitalized compensation costs in 2010 and 2009financial position were not significant.
A summary of activity related to nonqualified stock options follows:
Stock Options |
| Number of |
| Weighted Average |
| |
Outstanding-January 1, 2009 |
| 106,464 |
| $ | 27.44 |
|
Exercised |
| (2,875 | ) | 27.50 |
| |
Outstanding-December 31, 2009 |
| 103,589 |
| 27.44 |
| |
Exercised |
| (53,246 | ) | 27.40 |
| |
Outstanding-December 31, 2010 |
| 50,343 |
| 27.49 |
| |
Exercised |
| (40,267 | ) | 27.48 |
| |
Outstanding-December 31, 2011 |
| 10,076 |
| 27.52 |
| |
No stock options were granted or forfeited and all options were fully vested during the periods presented. The options expire ten years after their respective grant dates and all options currently outstanding will expire in 2012. At December 31, 2011, all outstanding options were currently exercisable at a price of $27.52, and had a weighted-average remaining contractual life of less than one year.
The exercise of stock options during the periods presented were satisfied using original issue shares. For the years ended December 31, 2011, 2010 and 2009, cash realized upon the exercise of options and related tax benefits were not significant.
Environmental
itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.4 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.
In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court
SCE&G has been named, along with 53 others, byfinalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020.
High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2013, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and has commenced construction of a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available.
Claims and Litigation
In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina. This settlement did not have a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition.
|
| Millions of dollars |
| |
2012 |
| $ | 7 |
|
2013 |
| 6 |
| |
2014 |
| 2 |
| |
2015 |
| 1 |
| |
2016 |
| — |
| |
Thereafter |
| 21 |
| |
Total |
| $ | 37 |
|
Purchase Commitments
Consolidated SCE&G is obligated for purchase commitments that expire at various dates through 2034. Amounts expended for coal supply, nuclear fuel contracts, construction projects and other commitments totaled $717.8 million in 2011, $859.7 million in 2010 and $756.9 million in 2009. Future payments under such purchase commitments are as follows:
|
| Millions of dollars |
| |
2012 |
| $ | 1,459 |
|
2013 |
| 965 |
| |
2014 |
| 836 |
| |
2015 |
| 767 |
| |
2016 |
| 773 |
| |
Thereafter |
| 1,038 |
| |
Total |
| $ | 5,838 |
|
| Millions of dollars | |||
| 2014 | $ | 4 | |
| 2015 | 3 | ||
| 2016 | 2 | ||
| 2017 | 1 | ||
| 2018 | 1 | ||
| Thereafter | 19 | ||
| Total | $ | 30 | |
The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s regulated utility operations. As of December 31, 2011,2013, Consolidated SCE&G has recorded an AROAROs of approximately $124$191 million for nuclear plant decommissioning (see Note 1) and an AROAROs of approximately $326$356 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.
Millions of dollars |
| 2011 |
| 2010 |
| ||
Beginning balance |
| $ | 478 |
| $ | 458 |
|
Liabilities incurred |
| — |
| 1 |
| ||
Liabilities settled |
| (4 | ) | (1 | ) | ||
Accretion expense |
| 23 |
| 24 |
| ||
Revisions in estimated cash flows |
| (47 | ) | (4 | ) | ||
Ending Balance |
| $ | 450 |
| $ | 478 |
|
| Millions of dollars | 2013 | 2012 | ||||||
| Beginning balance | $ | 535 | $ | 450 | ||||
| Liabilities incurred | 5 | — | ||||||
| Liabilities settled | (4 | ) | (5 | ) | ||||
| Accretion expense | 24 | 23 | ||||||
| Revisions in estimated cash flows | (13 | ) | 67 | |||||
| Ending Balance | $ | 547 | $ | 535 | ||||
SCE&G had approximately $1.3 million receivable from CGT for transportation services at December 31, 2013 and an insignificant receivable amount at December 31, 2012.
Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions was not significant for any period presented. At December 31, 2011 and 2010, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $58.5 million and $71.0 million, respectively.
2012.
&G, which are rendered at direct or allocated cost: information systems services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, and general administrative services. Costs for these services totaled $285.6 million in 2013,
$305.6 million in 2012 and $302.6 million in 2011.Note 1.
Disclosure of Reportable Segments (Millions of dollars)
|
| Electric |
| Gas |
| Adjustments/ |
| Consolidated |
| ||||
2011 |
|
|
|
|
|
|
|
|
| ||||
External Revenue |
| 2,432 |
| 387 |
| — |
| 2,819 |
| ||||
Operating Income |
| 616 |
| 40 |
| (2 | ) | 654 |
| ||||
Interest Expense |
| 23 |
| — |
| 181 |
| 204 |
| ||||
Depreciation and Amortization |
| 271 |
| 25 |
| (10 | ) | 286 |
| ||||
Segment Assets |
| 8,222 |
| 622 |
| 2,193 |
| 11,037 |
| ||||
Expenditures for Assets |
| 806 |
| 60 |
| (18 | ) | 848 |
| ||||
Deferred Tax Assets |
| 9 |
| n/a |
| (1 | ) | 8 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
2010 |
|
|
|
|
|
|
|
|
| ||||
External Revenue |
| $ | 2,374 |
| $ | 441 |
| $ | — |
| $ | 2,815 |
|
Intersegment Revenue |
| 554 |
| 52 |
| (2 | ) | 604 |
| ||||
Operating Income |
| 22 |
| — |
| 164 |
| 186 |
| ||||
Interest Expense |
| 263 |
| 22 |
| (14 | ) | 271 |
| ||||
Depreciation and Amortization |
| 7,882 |
| 590 |
| 2,102 |
| 10,574 |
| ||||
Segment Assets |
| 752 |
| 39 |
| (20 | ) | 771 |
| ||||
Expenditures for Assets |
| 5 |
| n/a |
| 10 |
| 15 |
| ||||
Deferred Tax Assets |
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
2009 |
|
|
|
|
|
|
|
|
| ||||
External Revenue |
| $ | 2,149 |
| $ | 420 |
| — |
| $ | 2,569 |
| |
Intersegment Revenue |
| — |
| 2 |
| $ | (2 | ) | — |
| |||
Operating Income |
| 505 |
| 43 |
| (1 | ) | 547 |
| ||||
Interest Expense |
| 15 |
| — |
| 149 |
| 164 |
| ||||
Depreciation and Amortization |
| 244 |
| 21 |
| (10 | ) | 255 |
| ||||
Segment Assets |
| 7,312 |
| 558 |
| 1,943 |
| 9,813 |
| ||||
Expenditures for Assets |
| 817 |
| 39 |
| (105 | ) | 751 |
| ||||
Deferred Tax Assets |
| n/a |
| n/a |
| n/a |
| n/a |
| ||||
Electric Operations | Gas Distribution | Adjustments/ Eliminations | Consolidated Total | |||||||||||||
| 2013 | ||||||||||||||||
| External Revenue | $ | 2,431 | $ | 414 | — | $ | 2,845 | |||||||||
| Operating Income | 679 | 58 | — | 737 | ||||||||||||
| Interest Expense | 19 | — | $ | 198 | 217 | |||||||||||
| Depreciation and Amortization | 294 | 26 | (7 | ) | 313 | |||||||||||
| Segment Assets | 9,488 | 686 | 2,526 | 12,700 | ||||||||||||
| Expenditures for Assets | 907 | 45 | 51 | 1,003 | ||||||||||||
| Deferred Tax Assets | 10 | n/a | (10 | ) | — | |||||||||||
| 2012 | ||||||||||||||||
| External Revenue | $ | 2,453 | $ | 356 | — | $ | 2,809 | |||||||||
| Operating Income | 668 | 49 | — | 717 | ||||||||||||
| Interest Expense | 21 | — | $ | 190 | 211 | |||||||||||
| Depreciation and Amortization | 278 | 25 | (10 | ) | 293 | |||||||||||
| Segment Assets | 8,989 | 659 | 2,456 | 12,104 | ||||||||||||
| Expenditures for Assets | 999 | 56 | (77 | ) | 978 | |||||||||||
| Deferred Tax Assets | 9 | n/a | (9 | ) | — | |||||||||||
| 2011 | ||||||||||||||||
| External Revenue | $ | 2,432 | $ | 387 | — | $ | 2,819 | |||||||||
| Operating Income | 616 | 40 | $ | (2 | ) | 654 | ||||||||||
| Interest Expense | 23 | — | 181 | 204 | ||||||||||||
| Depreciation and Amortization | 271 | 25 | (10 | ) | 286 | |||||||||||
| Segment Assets | 8,222 | 622 | 2,193 | 11,037 | ||||||||||||
| Expenditures for Assets | 806 | 60 | (18 | ) | 848 | |||||||||||
| Deferred Tax Assets | 9 | n/a | (1 | ) | 8 | |||||||||||
|
| First |
| Second |
| Third |
| Fourth |
| Annual |
| |||||
2011 Millions of dollars |
|
|
|
|
|
|
|
|
|
|
| |||||
Total operating revenues |
| $ | 704 |
| $ | 691 |
| $ | 797 |
| $ | 627 |
| $ | 2,819 |
|
Operating income |
| 151 |
| 137 |
| 220 |
| 146 |
| 654 |
| |||||
Net income attributable to SCE&G |
| 68 |
| 59 |
| 117 |
| 62 |
| 306 |
| |||||
2010 Millions of dollars |
|
|
|
|
|
|
|
|
|
|
| |||||
Total operating revenues |
| $ | 722 |
| $ | 652 |
| $ | 777 |
| $ | 664 |
| $ | 2,815 |
|
Operating income |
| 123 |
| 138 |
| 198 |
| 145 |
| 604 |
| |||||
Net income attributable to SCE&G |
| 62 |
| 60 |
| 106 |
| 62 |
| 290 |
| |||||
139
| Millions of dollars | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Annual | |||||||||||||||
| 2013 | ||||||||||||||||||||
| Total operating revenues | $ | 728 | $ | 696 | $ | 776 | $ | 645 | $ | 2,845 | ||||||||||
| Operating income | 191 | 180 | 255 | 111 | 737 | |||||||||||||||
| Net Income | 92 | 88 | 139 | 72 | 391 | |||||||||||||||
| Earnings Available to Common Shareholder | 89 | 85 | 136 | 70 | 380 | |||||||||||||||
| 2012 | ||||||||||||||||||||
| Total operating revenues | $ | 663 | $ | 661 | $ | 777 | $ | 708 | $ | 2,809 | ||||||||||
| Operating income | 156 | 165 | 241 | 155 | 717 | |||||||||||||||
| Net Income | 72 | 78 | 132 | 70 | 352 | |||||||||||||||
| Earnings Available to Common Shareholder | 69 | 76 | 129 | 67 | 341 | |||||||||||||||
ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING SCE&G: PART IIINot Applicable.SCANA:Evaluation of Disclosure Controls and Procedures:As of December 31, 2011,2013, an evaluation was performed under the supervision and with the participation of SCANA’s management, including the CEO and CFO, of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussionsdecisions regarding required disclosure. Based on that evaluation, SCANA’s management, including the CEO and CFO, concluded that SCANA’s disclosure controls and procedures were effective as of December 31, 2011.2013.Management’s Evaluation of Internal Control Over Financial Reporting:As of December 31, 2013, an evaluation was performed under the supervision and with the participation of SCANA’s management, including the CEO and CFO, of any change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2013. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 20112013 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.Management’s Evaluation of Internal Control Over Financial Reporting:Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2011,2013, the effectiveness of such structure and procedures. This management report follows.MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGThe management of SCANA is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA’s internal control system was designed by or under the supervision of SCANA’s management, including the CEO and CFO, to provide reasonable assurance to SCANA’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.SCANA’s management assessed the effectiveness of SCANA’s internal control over financial reporting as of December 31, 2011.2013. 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 (1992). Based on this assessment, SCANA’s management believes that, as of December 31, 2011,2013, 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.151REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Stockholders ofSCANA CorporationCayce, South CarolinaWe have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the “Company”"Company") as of December 31, 2011,2013, based on criteria established in Internal Control—Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’sCompany'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’sCompany'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’scompany's internal control over financial reporting is a process designed by, or under the supervision of, the company’scompany's principal executive and principal financial officers, or persons performing similar functions, and effected by the company’scompany'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’scompany'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’scompany's assets that could have a material effect on the financial statements.Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011,2013, based on the criteria established in Internal Control-IntegratedControl - Integrated Framework (1992) 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, 20112013, of the Company and our report dated February 29, 2012,28, 2014, expressed an unqualified opinion on those financial statements and financial statement schedule.152Evaluation of Disclosure Controls and Procedures:As of December 31, 2011,2013, an evaluation was performed under the supervision and with the participation of SCE&G’s management, including the CEO and CFO, of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussionsdecisions regarding required disclosure. Based on that evaluation, SCE&G’s management, including the CEO and CFO, concluded that SCE&G’s disclosure controls and procedures were effective as of December 31, 2011.2013.Management’s Evaluation of Internal Control Over Financial Reporting:As of December 31, 2013, an evaluation was performed under the supervision and with the participation of SCE&G’s management, including the CEO and CFO, of any change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2013. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 20112013 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.Management’s Evaluation of Internal Control Over Financial Reporting:Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2011,2013, the effectiveness of such structure and procedures. This management report follows.MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGThe management of SCE&G is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G’s internal control system was designed by or under the supervision of SCE&G’s management, including the CEO and CFO, to provide reasonable assurance to SCE&G’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.SCE&G’s management assessed the effectiveness of SCE&G’s internal control over financial reporting as of December 31, 2011.2013. 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 (1992). Based on this assessment, SCE&G’s management believes that, as of December 31, 2011,2013, internal control over financial reporting is effective based on those criteria.ITEM 9B. OTHER INFORMATION153Not applicable.
Plan Category Number of Weighted-average Number of securities (a) (b) (c) Equity compensation plans approved by security holders: Long-Term Equity Compensation Plan 10,076 27.52 3,138,638 Non-Employee Director Compensation Plan n/a n/a 153,509 Equity compensation plans not approved by security holders n/a n/a n/a Total 10,076 27.52 3,292,147 SCANA: A list of SCANA’s executive officers is in Part I of this annual report at page 26.25. The other information required by Item 10 is incorporated herein by reference to the captions “NOMINEES FOR DIRECTORS,” “CONTINUING DIRECTORS,” “BOARD MEETINGS-COMMITTEES OF THE BOARD”, “GOVERNANCE INFORMATION-SCANA’s Code of Conduct & Ethics” and “OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance” in SCANA’s definitive proxy statement for the 20122014 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. SCANA: The information required by Item 11 is incorporated herein by reference to the captions “COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION,“Compensation Committee Interlocks and Insider Participation,” “COMPENSATION DISCUSSION AND ANALYSIS,“Compensation Discussion and Analysis,” COMPENSATION COMMITTEE REPORT,Compensation Committee Report,” “SUMMARY COMPENSATION TABLE,“Summary Compensation Table,” “2011 GRANTS OF PLAN-BASED AWARDS,“2013 Grants of Plan-Based Awards,” “OUTSTANDING EQUITY AWARDS AT 2011 FISCAL YEAR-END,“Outstanding Equity Awards at 2013 Fiscal Year-End,” “2011 OPTION EXERCISES AND STOCK VESTED,“2013 Option Exercises and Stock Vested,” “PENSION BENEFITS,“Pension Benefits,” “2011 NONQUALIFIED DEFERRED COMPENSATION,“2013 Nonqualified Deferred Compensation,” and “POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL,“Potential Payments Upon Termination or Change in Control,” under the heading “EXECUTIVE COMPENSATION” and the heading “2011 DIRECTOR“DIRECTOR COMPENSATION” in SCANA’s definitive proxy statement for the 20122014 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 MATTERSSCANA: 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 20122014 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, 20112013 are summarized as follows:
securities
to be issued
upon exercise
of outstanding
options, warrants
and rights
exercise price
of outstanding options,
warrants
and rights
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))Plan Category Number ofsecuritiesto be issuedupon exerciseof outstandingoptions, warrantsand rightsWeighted-averageexercise priceof outstanding options,warrantsand rightsNumber of securitiesremaining availablefor future issuanceunder equitycompensation plans(excluding securitiesreflected in column (a))(a) (b) (c) Equity compensation plans approved by security holders: - Long-Term Equity Compensation Plan n/a n/a 3,138,638 Non-Employee Director Compensation Plan n/a n/a 100,886 Equity compensation plans not approved by security holders n/a n/a n/a Total n/a n/a 3,239,524 SCE&G: Not applicable.154SCANA: The information required by Item 13 is incorporated herein by reference to the caption “RELATED PARTY TRANSACTIONS” in SCANA’s definitive proxy statement for the 20122014 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.144SCE&G: Not applicable.
2011 2010 Audit Fees(1) $ 1,754,899 $ 1,594,800 Audit-Related Fees(2) 66,957 66,713 Total Fees $ 1,821,856 $ 1,661,513 SCANA: The information required by Item 14 is incorporated herein by reference to “PROPOSAL 4-APPROVAL2-APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in SCANA’s definitive proxy statement for the 20122014 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 FeesThe 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, 20112013 and 20102012 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates. 2013 2012 Audit Fees (1) $ 1,972,696 $ 1,772,129 Audit-Related Fees (2) 115,706 258,357 Total Fees $ 2,088,402 $ 2,030,486 (1)Fees for audit services billed in 20112013 and 20102012 consisted of audits of annual financial statements, comfort letters, statutory and regulatory audits, consents and other services related to SEC filings, and accounting research.(2)Fees primarily for employee benefit plan audits and, in 2012, for 2011 and 2010.145non-statutory audit services.155
PART IV
Schedule II—Valuation and Qualifying Accounts Additions Description Beginning Charged to Charged to Deductions Ending SCANA: Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2011 $ 9 $ 17 — $ 20 $ 6 2010 9 28 — 28 9 2009 11 17 — 19 9 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2011 $ 5 $ 4 — $ 3 $ 6 2010 7 1 — 3 5 2009 6 4 — 3 7 SCE&G: Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2011 $ 3 $ 6 — $ 6 $ 3 2010 3 6 — 6 3 2009 3 6 — 6 3 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2011 $ 4 $ 2 — $ 2 $ 4 2010 5 1 — 2 4 2009 5 3 — 3 5 (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 areis 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) ExhibitsExhibits 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.156(in millions)
Balance
Income
Other
Accounts
from
Reserves
Balance147 Additions Description BeginningBalance Charged toIncome Charged toOtherAccounts DeductionsfromReserves EndingBalanceSCANA: Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2013 $ 7 $ 13 — $ 14 $ 6 2012 6 14 — 13 7 2011 9 17 — 20 6 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2013 $ 6 $ 4 — $ 4 $ 6 2012 6 4 — 4 6 2011 5 4 — 3 6 SCE&G: Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2013 $ 3 $ 7 — $ 7 $ 3 2012 3 6 — 6 3 2011 3 6 — 6 3 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2013 $ 5 $ 3 — $ 3 $ 5 2012 4 3 — 2 5 2011 4 2 — 2 4 157
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| BY: | /s/ K. B. | |
K. B. Marsh, Chairman of the Board, President, Chief Executive Officer, Chief Operating Officer and Director | ||
DATE: | February | |
| /s/ K. B. | |||
K. B. Marsh, Chairman of the Board, President, Chief Executive Officer, Chief Operating Officer and Director | |||
(Principal Executive Officer) | |||
/s/ J. E. | |||
J. E. Addison Executive Vice President and Chief Financial Officer | |||
(Principal Financial Officer) | |||
/s/ J. E. | |||
J. E. Swan, IV Controller | |||
(Principal Accounting Officer) | |||
Other Directors*: | |||
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J. A. Bennett | L. M. Miller | ||
| J. W. Roquemore | ||
D. M. Hagood | M. K. Sloan | ||
J. W. Martin, III | H. C. Stowe | ||
| J. M. Micali | A. Trujillo | ||
14828, 2014
SIGNATURES
| SOUTH CAROLINA ELECTRIC & GAS COMPANY | ||
BY: | /s/ K. B. | |
K. B. Marsh, Chairman of the Board, Chief Executive Officer and Director | ||
DATE: | February | |
| /s/ K. B. | ||
K. B. Marsh, Chairman of the Board, Chief Executive Officer and Director | ||
(Principal Executive Officer) | ||
/s/ J. E. | ||
J. E. Addison Executive Vice President and Chief Financial Officer | ||
(Principal Financial Officer) | ||
/s/ J. E. | ||
J. E. Swan, IV | ||
(Principal Accounting Officer) | ||
Other Directors*: | ||
| J. W. Roquemore | |
| D. M. Hagood | M. K. Sloan | |
| J. M. Micali | H. C. Stowe | |
| L. M. Miller | ||
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* Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact
14928, 2014
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| Exhibit | Applicable to Form 10-K of | ||||||
No. | SCANA | SCE&G | Description | ||||
3.01 |
| X | Restated Articles of Incorporation of SCANA, | ||||
| 3.02 | X | ||||||
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| 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 | ||||||
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| 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 | ||||||
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| Restated Articles of Incorporation of | |||||
| 3.05 | X | ||||||
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| By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein) | |||||
| 3.06 | X | ||||||
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| 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 | |||||
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| Articles of Exchange of | ||||
| 4.02 | X | ||||||
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| Indenture dated as of November 1, 1989 between SCANA | |||||
| 4.03 | X | ||||||
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| First Supplemental Indenture dated as of November 1, 2009 to Indenture dated as of November 1, 1989 between SCANA | |||||
| 4.04 | X | ||||||
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| Junior Subordinated Indenture dated as of November 1, 2009 between SCANA | |||||
| 4.05 | X | ||||||
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| First Supplemental Indenture to Junior Subordinated Indenture referred to in Exhibit 4.04 dated as of November 1, 2009 (Filed as Exhibit 99.03 to Registration Statement No. 333-174796 and incorporated by reference herein) | |||||
| 4.06 | X | ||||||
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| Indenture dated as of April 1, 1993 from | |||||
| 4.07 | X | ||||||
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| First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein) | |||||
| 4.08 | X | ||||||
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| Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein) | |||||
| 4.09 | X | Third Supplemental Indenture to Indenture referred to in Exhibit 4.06 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) | |||||
150
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| 10.01 | X | X | |||||||||||
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| Engineering, Procurement and Construction Agreement, dated May 23, 2008, between | ||||||||||
| 10.02 | X | X | |||||||||||
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| Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and | ||||||||||
| *10.03 | X | X | |||||||||||
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| SCANA Executive Deferred Compensation Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.04 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.04 | X | X | |||||||||||
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| SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.05 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.05 | X | X | |||||||||||
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| SCANA Director Compensation and Deferral Plan (including amendments through April 21, 2011) (Filed as Exhibit 4.05 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.06 | X | X | |||||||||||
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| SCANA Long-Term Equity Compensation Plan as amended and restated (including amendments through December 31, 2009) (Filed as Exhibit 99.06 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.07 | X | X | |||||||||||
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| SCANA Supplementary Executive Benefit Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.07 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.08 | X | X | |||||||||||
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| SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.08 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.09 | X | X | |||||||||||
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| SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.09 to Registration Statement No. 333-174796 and incorporated by reference herein) | ||||||||||
| *10.10 | X | X | |||||||||||
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| Description of SCANA Whole Life Option (Filed as Exhibit 10-F for the year ended December 31, 1991, under cover of Form SE | ||||||||||
| 10.11 | X | ||||||||||||
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| 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) | |||||||||||
| 10.12 | 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) | |||||||||||
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| X | Amended and Restated Five-Year Credit Agreement dated as of October 25, 2012, by and among SCANA; 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 JPMorgan Chase Bank, N.A., Mizuho Corporation Bank, LTD. and TD Bank N.A., as Documentation Agents (Filed as Exhibit 99.1 to Form 8-K on October 30, 2012 (File No. 001-08809) and incorporated by reference herein) | ||||||||||
| 10.14 | X | X | Amended and Restated Five-Year Credit Agreement dated as of October 25, 2012, 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. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC, as Documentation Agents (Filed as Exhibit 99.2 to Form 8-K on October 30, 2012 (File No. 001-08809 (SCANA); File No. 001-00375 (SCE&G)) and incorporated by reference herein) | ||||||||||
| 10.15 | X | X | Three-Year Credit Agreement dated as of October 25, 2012, 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. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC, as Documentation Agents (Filed as Exhibit 99.3 to Form 8-K on October 30, 2012 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein) | ||||
| 10.16 | X | X | Amended and Restated Five-Year Credit Agreement dated as of October 25, 2012, 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 JPMorgan Chase Bank, N.A., Mizuho Corporation Bank, LTD. and TD Bank N.A., as Documentation Agents (Filed as Exhibit 99.4 to Form 8-K on October 30, 2012 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein) | ||||
| 10.17 | X | Amended and Restated Five-Year Credit Agreement dated as of October 25, 2012, 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 JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, LTD. and TD Bank N.A., as Documentation Agents (Filed as Exhibit 99.5 to Form 8-K on October 30, 2012 (File No. 001-08809) and incorporated by reference herein) | |||||
| 12.01 | X | X | Statement Re Computation of Ratios (Filed herewith) | ||||
| 21.01 | X | ||||||
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| Subsidiaries of the registrant (Filed herewith under the heading “Corporate | |||||
| 23.01 | X | ||||||
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| Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith) | |||||
| 23.02 | X | ||||||
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| Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith) | |||||
| 24.01 | X | ||||||
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| Power of Attorney (Filed herewith) | |||||
| 24.02 | X | ||||||
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| Power of Attorney (Filed herewith) | |||||
| 31.01 | X | ||||||
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| Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) | |||||
| 31.02 | X | ||||||
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| Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) | |||||
| 31.03 | X | ||||||
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| Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) | |||||
| 31.04 | X | ||||||
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| Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) | |||||
| 32.01 | X | ||||||
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| Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |||||
| 32.02 | X | ||||||
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| Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |||||
| 32.03 | X | ||||||
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| Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |||||
| 32.04 | X | ||||||
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| Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |||||
101. INS** | X | X | XBRL Instance Document | ||||
101. SCH** | X | X | XBRL Taxonomy Extension Schema | ||||
101. CAL** | X | X | XBRL Taxonomy Extension Calculation Linkbase | ||||
101. DEF** | X | X | XBRL Taxonomy Extension Definition Linkbase | ||||
101. LAB** | X | X | XBRL Taxonomy Extension Label Linkbase | ||||
101. PRE** | X | X | XBRL Taxonomy Extension Presentation Linkbase | ||||
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| * | 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. | |