SCANA 10-Q 2011
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
For the quarterly period ended March 31, 2011
For the Transition Period from to
Indicate 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 o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
SCANA Corporation Yes o No x South Carolina Electric & Gas Company Yes o No x
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date.
(a) Held beneficially and of record by SCANA Corporation.
This combined Form 10-Q is separately filed by SCANA Corporation and South Carolina Electric & Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other company.
South Carolina Electric & Gas Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this Form with the reduced disclosure format allowed under General Instruction H(2).
MARCH 31, 2011
Statements included in this Quarterly Report on Form 10-Q 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:
SCANA and SCE&G disclaim any obligation to update any forward-looking statements.
The following abbreviations used in the text have the meanings set forth below unless the context requires otherwise:
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.
(1) Accumulated other comprehensive loss totaled $40.0 million as of March 31, 2011 and $46.6 million as of December 31, 2010.
See Notes to Condensed Consolidated Financial Statements.
March 31, 2011
The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANAs Annual Report on Form 10-K for the year ended December 31, 2010. These are interim financial statements and, due to the seasonality of the Companys business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Earnings Per Share
The Company computes basic earnings per share by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The Company has issued no securities that would have an antidilutive effect on earnings per share.
A reconciliation of the weighted average number of common shares for year to date March 31 for basic and dilutive purposes is as follows:
Asset Management and Supply Service Agreements
PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At March 31, 2011, such counterparties held 40% of PSNC Energys natural gas inventory, with a carrying value of $8.3 million, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire at various times through March 31, 2013.
2. RATE AND OTHER REGULATORY MATTERS
SCE&Gs electric rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&Gs 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 is allowed to charge and recover 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 filed for an increase to the cost of fuel component of its rates to be effective with the first billing cycle of May 2011. The annual fuel hearing was conducted on March 24, 2011, and a
settlement agreement was reached among ORS, the SCEUC, and SCE&G which will allow SCE&G to recover the actual base fuel under-collected balance as of April 30, 2011, over a two year period and charge carrying cost on the deferred balance. The settlement was approved by the SCPSC on April 20, 2011 and is effective with the first billing cycle of May 2011.
On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&Gs retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSCs order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other things, the SCPSCs order (1) included implementation of an eWNA for SCE&Gs electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&Gs 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&Gs customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.
On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. The SCPSCs order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the DSM rate rider tariff sheet with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits. In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.
In December 2009, SCE&G submitted to the FERC revised tariff sheets to change the network and point to point transmission rates under SCE&Gs OATT. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. In compliance with the OATT, on March 1, 2010 pursuant to an order issued by the FERC, SCE&G implemented, subject to refund, the proposed tariff sheets. On May 17, 2010, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or Annual Update for the period June 1, 2010 through May 31, 2011. The FERC accepted the tariff sheets in the Annual Update and made them effective, subject to refund, as of June 1, 2010.
In January 2010, the SCPSC approved SCE&Gs 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. The revised schedule does not change the previously announced completion date for the New Units or the originally announced cost.
In February 2009, the SCPSC approved SCE&Gs 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, including contingencies, as approved by the SCPSC.
In May 2009, two intervenors filed separate appeals of the order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSCs 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 SCPSCs 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&Gs share of the project, as originally approved by the SCPSC, is $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 Courts ruling, however, does not affect the project schedule or disturb the SCPSCs 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 to the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and on March 28, 2011, SCE&G and the ORS entered into a settlement agreement which stated, among other things, that this updated capital cost schedule should be approved by the SCPSC. A hearing on this petition was held on April 4, 2011, and the SCPSC is expected to rule on the request in May 2011.
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&Gs updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2009, the SCPSC approved SCE&Gs annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, 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, 2010.
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. On October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%. The rate adjustment was effective with the first billing cycle of November 2010.
SCE&Gs natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&Gs gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&Gs gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&Gs gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.
In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&Gs natural gas hedging program. SCE&G responded in March 2011 indicating no objection to the ORSs request. The request is subject to approval by the SCPSC. The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held on April 21, 2011.
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 PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.
PSNC Energys rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and defers any over- or under-collections of the delivered cost of gas for subsequent rate consideration. The NCUC reviews PSNC Energys 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 October 2010, in connection with PSNC Energys 2010 Annual Prudence Review, the NCUC determined that PSNC Energys gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2010.
Regulatory Assets and Regulatory Liabilities
The Companys cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and liabilities which are summarized in the following tables. Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods. These amounts are expected to be recovered in retail electric rates during the period May 2012 through April 2013. SCE&G is allowed to recover interest on the base fuel deferred balances through the recovery period.
Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assets are expected to be recovered over periods of up to approximately 19 years.
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 95 years.
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become longer at the direction of the SCPSC.
Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.
Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate swaps, treasury rate locks and forward starting swap agreements designated as cash flow hedges. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.
Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.
Other asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.
The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates. During the first quarter of 2011 and 2010, SCE&G applied costs of $0.7 million to the reserve. Pursuant to the SCPSCs July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds 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 the year 2024.
The SCPSC or the NCUC (collectively, state public service commissions) or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by a state public service commission or by the FERC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Companys results of operations, liquidity or financial position in the period the write-off would be recorded.
3. COMMON EQUITY
SCANA issued common stock valued at $25.4 million (at time of issue) during the three months ended March 31, 2011 through various compensation and dividend reinvestment plans (including the Stock Purchase Savings Plan), including the exercise of approximately 19,600 stock options during the period. In addition, in May 2010 SCANA entered into forward sale contracts for approximately 6.6 million common shares to be settled no later than February 29, 2012. There have been no shares issued under the forward sales contracts.
4. LONG-TERM DEBT AND LIQUIDITY
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 $150 million of medium term notes due February 15, 2011.
In January 2011, SCE&G issued $250 million of 5.45% first mortgage bonds maturing on February 1, 2041. Proceeds from the sale were used to retire $150 million of First Mortgage Bonds due February 1, 2011, to repay short-term debt and for general corporate purposes.
Substantially all of SCE&Gs and GENCOs electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.
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:
(a) The Companys committed long-term facilities serve to back-up the issuance of commercial paper or to provide liquidity support. Commercial paper can be issued in the amounts of up to $300 million by SCANA, $700 million by SCE&G, $400 million by Fuel Company and $100 million by PSNC Energy.
SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015. These credit agreements are used for general corporate purposes, including liquidity support for each companys commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%. Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCANA, SCE&G (including Fuel Company) and PSNC Energy.
The Company is obligated with respect to an aggregate of $71.4 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company. These letters of credit expire, subject to renewal, in the fourth quarter of 2011.
5. INCOME TAXES
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 first quarter of 2011, pursuant to an SCPSC order, SCE&G continued the accelerated recognition of additional previously deferred state income tax credits (see Note 2). No other material changes in the status of the Companys tax positions have occurred through March 31, 2011.
In connection with the change in method of accounting for certain repair costs in 2010, the Company identified approximately $36 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.
The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties.
6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings, as a component of other comprehensive income (loss) or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. SCANAs Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Companys Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Boards 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.
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.
The Companys regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&Gs tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCE&Gs hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energys tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.
The unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in other comprehensive income. When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from other comprehensive income to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.
As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives.
Interest Rate Swaps
The Company uses interest rate swaps to manage interest rate risk on certain debt issuances. These swaps are designated as either fair value hedges or cash flow hedges.
The Company uses swaps to synthetically convert fixed rate debt to variable rate debt. These swaps are designated as fair value hedges. Gains on certain swaps which were terminated prior to maturity of the underlying debt instruments are being amortized over the life of the debt they hedged.
The Company also uses swaps to synthetically convert variable rate debt to fixed rate debt. In addition, in anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements which are designated as cash flow hedges. The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities, and for the holding company or nonregulated subsidiaries, are recorded in other comprehensive income. Ineffective portions of changes in fair value are recognized in income.
The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the condensed consolidated statements of cash flows.
Quantitative Disclosures Related to Derivatives
The Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes an aggregate 8,950,000 DT related to basis swap contracts in Energy Marketing.
(b) Includes an aggregate 6,485,536 DT related to basis swap contracts in Energy Marketing.
At each of March 31, 2011 and December 31, 2010, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $556.4 million, and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $977.0 million and $1.1 billion, respectively.
The fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheet as follows:
(c) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses. In the Companys condensed consolidated balance sheets, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability.
The effect of derivative instruments on the statements of income is as follows:
Derivatives in Fair Value Hedging Relationships
With regard to the Companys interest rate swaps designated as fair value hedges, the gains on those swaps and the losses on the hedged fixed rate debt are recognized in current earnings and included in interest expense. These gains and losses, combined with the amortization of deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $2.5 million and $3.0 million for the three months ended March 31, 2011 and 2010, respectively.
Derivatives in Cash Flow Hedging Relationships
As of March 31, 2011, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $0.9 million as an increase to gas cost and approximately $2.1 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of March 31, 2011, all of the Companys commodity cash flow hedges settle by their terms before the end of 2013.
Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three months ended March 31, 2011 and 2010.
Credit Risk Considerations
Certain of the Companys derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of March 31, 2011 and December 31, 2010, the Company has posted $19.7 million and $20.0 million, respectively, of collateral related to derivatives with contingent provisions that are in a net liability position. If all of the contingent features underlying these instruments were fully triggered as of March 31, 2011 and December 31, 2010, the Company would be required to post an additional $38.5 million and $74.0 million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2011 and December 31, 2010 are $58.2 million and $94.0 million, respectively.
7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Companys interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition, there were no transfers of fair value amounts into or out of Levels 1 and 2 during any period presented.
Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2011 and December 31, 2010 were as follows:
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on discounted cash flow models with independently sourced data. Early settlement of long-term debt may not be possible or may not be considered prudent. Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.
8. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefit Plans
Components of net periodic benefit cost recorded by the Company were as follows:
Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in current rates for SCE&Gs retail electric and gas distribution regulated operations. In connection with the SCPSCs July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable. Costs totaling $2.3 million and $ 5.3 million were deferred for the three months ended March 31, 2011 and 2010, respectively.
9. COMMITMENTS AND CONTINGENCIES
The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.6 billion. Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year. SCE&Gs maximum assessment, based on its two-thirds ownership of Summer Station, would be $78.3 million per incident, but not more than $11.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurers losses. Based on the current annual premium, SCE&Gs portion of the retrospective premium assessment would not exceed $14.2 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material adverse impact on the Companys results of operations, cash flows and financial position.
In 2005, the EPA issued the CAIR, which requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction, and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction. SCE&G also installed a wet limestone scrubber at Wateree Station. In July 2010, the EPA proposed a revised rule known as the Clean Air Transport Rule which will replace CAIR once promulgated. The proposed 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.
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 proposed rule provides up to four years for facilities to meet the standards once promulgated. The EPA is expected to finalize the rule in November 2011. The proposed 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 maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and expects to recover them through rates.
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $8.8 million. In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites through rates. At March 31, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.9 million and are included in regulatory assets.
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energys 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 $3.6 million, which reflects its estimated remaining liability at March 31, 2011. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.
SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station. The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New Units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019. SCE&G will be the operator of the New Units. SCE&Gs share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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.
SCE&Gs latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&Gs need for 55 percent of the output of the two units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. Santee Cooper has more recently indicated that it will seek to reduce its 45 percent ownership in the New Units. Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Coopers ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Coopers 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.
10. SEGMENT OF BUSINESS INFORMATION
The Companys reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, income available to common shareholders is not allocated to the Electric Operations and Gas Distribution segments. The Company uses income available to common shareholders to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes equity method investments and other nonreportable segments. One of these nonreportable segments operates a FERC-regulated interstate pipeline company and the others conduct nonregulated operations in energy-related and telecommunications industries.
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Managements Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANAs Annual Report on Form 10-K for the year ended December 31, 2010.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2011
AS COMPARED TO THE CORRESPONDING PERIODS IN 2010
Earnings Per Share
Earnings per share was as follows:
Basic earnings per share decreased by $.10 due to lower gas margin, $.02 due to higher property taxes, $.02 due to higher depreciation expense, $.02 due to higher interest expense and by dilution from additional shares outstanding of $.03. These decreases were partially offset by $.16 due to higher electric margin and by $.01 due to lower operating expenses which are explained below.
SCANAs Board of Directors has declared the following dividends on common stock during 2011: