SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
For the quarterly period ended September 30, 2009
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 o 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 issuer’s classes of common stock, as of the latest practicable date.
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.
SEPTEMBER 30, 2009
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
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,” “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) the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment;
(2) regulatory actions, particularly changes in rate regulation and environmental regulations;
(3) current and future litigation;
(4) changes in the economy, especially in areas served by subsidiaries of SCANA Corporation (SCANA);
(5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial
(6) growth opportunities for SCANA’s regulated and diversified subsidiaries;
(7) the results of short- and long-term financing efforts, including future prospects for obtaining access to
capital markets and other sources of liquidity;
(8) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;
(9) the effects of weather, including drought, especially in areas where the generation and transmission
facilities of SCANA and its subsidiaries are located and in areas served by SCANA’s subsidiaries;
(10) payment by counterparties as and when due;
(11) the results of efforts to license, site, construct and finance facilities for baseload electric generation;
(12) 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
(13) performance of SCANA’s pension plan assets;
(15) compliance with regulations; and
(16) the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or
South Carolina Electric & Gas Company (SCE&G) with the United States Securities and Exchange
SCANA and SCE&G disclaim any obligation to update any forward-looking statements.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
See Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation’s (SCANA and, together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2008. These are interim financial statements, and due to the seasonality of the Company’s 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. The Company has evaluated subsequent events through November 4, 2009, which is the date these financial statements were issued.
On July 1, 2009 the Financial Accounting Standards Board (FASB) Accounting Standards Codification (the Codification or ASC) became the single source of authoritative accounting principles generally accepted in the United States (GAAP). Throughout these notes, references to previous GAAP have been replaced with references to the ASC.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and regulatory liabilities, summarized as follows.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings which are expected to be recovered in retail electric rates during the period October 2010 through April 2012. As a part of a settlement agreement approved by the SCPSC in April 2009, SCE&G is allowed to collect interest on the deferred balance during the recovery period.
Environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by South Carolina Electric & Gas Company (SCE&G) are being recovered through rates, of which $19.3 million, net of insurance recovery, remain to be recovered. SCE&G is authorized to amortize $1.4 million of these costs annually. At sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy), costs of $2.4 million are being recovered through rates over a period ending October
2011. In addition, management believes that estimated remaining costs of $4.4 million, net of insurance recovery, will be recoverable through rates.
Asset retirement obligations (ARO) and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) and conditional AROs.
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.
Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities, and costs deferred pursuant to specific regulatory orders (Note 1C), but which are expected to be recovered through utility rates.
Other asset removal costs represent net collections through depreciation rates of estimated costs to be incurred for the removal of assets in the future.
The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates. During the nine months ended September 30, 2009 and 2008, SCE&G applied costs of $1.6 million and $3.7 million, respectively, to the reserve.
Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in advance of the time the costs are incurred, as approved through specific SCPSC orders. SCE&G is collecting $8.5 million annually, ending December 2013, through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.
The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which will be amortized into operating revenue through the year 2024.
The SCPSC or the North Carolina Utilities Commission (NCUC) (collectively, state commissions) or the United States Federal Energy Regulatory Commission (FERC) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by a state commission or by FERC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. In addition, the Company has deferred in utility plant in service approximately $74.2 million of unrecovered costs related to the Lake Murray backup dam project and $70.1 million of costs related to the installation of selective catalytic reactor (SCR) technology at its Cope Station generating facility. See Note 7B. These costs are not currently being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria of accounting for rate-regulated utilities, and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.
B. Earnings Per Share
The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has issued no securities that would have an antidilutive effect on earnings per share.
C. Pension and Other Postretirement Benefit Plans
Components of net periodic benefit income or cost recorded by the Company were as follows:
In February 2009, SCE&G was granted accounting orders by the SCPSC to allow the deferral until future rate filings of pension expense related to its utility operations above that which is included in current rates. Costs totaling $7.8 million of the $10.6 million for the three months ended September 30, 2009 have been deferred. Costs totaling $23.4 million of the $30.0 million for the nine months ended September 30, 2009 have been deferred.
D. New Accounting Matters
The Company adopted Statement of Financial Accounting Standards (SFAS) 165, codified as ASC 855, Subsequent Events, effective June 30, 2009. ASC 855 makes the Company’s management responsible for subsequent-events accounting and disclosure. The adoption of SFAS 165 did not impact the Company’s results of operations, cash flows or financial position.
The Company adopted FASB Staff Position FAS 107-1 and APB 28-1, codified as ASC 825, Financial Instruments, effective June 30, 2009. This Staff Position amended previous guidance to require certain disclosures related to fair value in interim financial statements. See Note 6 for the required disclosure.
The Company adopted SFAS 161, codified as ASC 815, Derivatives and Hedging, in the first quarter of 2009. ASC 815 requires enhanced disclosures about an entity’s derivative and hedging activities to include how derivative instruments are accounted for and the effect of such activities on the entity’s financial statements. The initial adoption of SFAS 161 did not impact the Company’s results of operations, cash flows or financial position. See Note 5 for the required disclosure.
The Company adopted SFAS 160, codified as ASC 810, Consolidation in the first quarter of 2009. ASC 810 requires entities to report noncontrolling (minority) interests in subsidiaries as equity. The initial adoption of FAS 160 did not significantly impact the Company’s results of operations, cash flows or financial position.
The Company adopted SFAS 141(R), codified as ASC 805, Business Combinations in the first quarter of 2009. ASC 805 requires the acquiring entity in a business combination to recognize the assets acquired and the liabilities assumed at their fair values at the acquisition date. ASC 805 also requires the acquiring entity to disclose all of the information needed to evaluate and understand the nature and financial effect of the business combination. The initial adoption of SFAS 141(R) did not impact the Company’s results of operations, cash flows or financial position.
FASB Staff Position FAS 132(R-1), codified as ASC 715-20-65-2, Compensation-Retirement Benefits, was issued on December 30, 2008. ASC 715-20-65-2 amends previous guidance to require enhanced disclosures about an employer’s plan assets in a defined benefit pension plan or other postretirement plan. The required disclosures include a discussion of the inputs and evaluation techniques used to develop fair value measurements of plan assets. In addition, the fair value of each major category of plan assets is required to be disclosed separately for pension plans and other postretirement benefit plans. ASC 715-20-65-2 is effective for fiscal years ending after December 15, 2009 and its initial adoption is not expected to affect the Company’s results of operations, cash flows or financial position.
E. Preferred Stock
The Company has corrected the presentation of the preferred stock not subject to purchase or sinking funds to present these preferred securities in a manner consistent with temporary equity. Although the effects are not material to previously issued balance sheets, the presentation of these amounts has been corrected as of December 31, 2008 by presenting these $106 million of preferred securities separately from common equity and eliminating the “Shareholders’ Investment” section and related total. This change had no impact on income, earnings per share, or on cash flows for any period presented.
F. Income Taxes
In September 2009, an income tax uncertainty was resolved in the Company’s favor upon the receipt of a favorable ruling in litigation of a state tax issue, which resulted in a refund of $15 million in state income taxes, plus interest. While the total of this tax benefit that will impact the effective tax rate will be $15 million, such impact is not expected to be material in the current or future years because, under regulatory accounting provisions, the tax benefit recorded is being amortized into earnings over the remaining life of property additions that gave rise to the tax benefit. No other material changes in the status of the Company’s tax positions have occurred through September 30, 2009.
G. Asset Management and Supply Service Agreements
PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At September 30, 2009, such counterparties held 48% of PSNC Energy’s natural gas inventory, with a carrying value of $32 million, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees and, in certain instances, a share of profits. No fees are received under supply service agreements. The agreements expire at various times through March 31, 2011.
2. RATE AND OTHER REGULATORY MATTERS
SCE&G’s rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In April 2009, the SCPSC approved a settlement agreement between SCE&G, the South Carolina Office of Regulatory Staff (ORS), and others authorizing SCE&G to increase the fuel cost portion of its electric rates, effective with the first billing cycle of May 2009. As a part of the settlement, SCE&G agreed to spread the recovery of undercollected fuel costs over a three-year period ending April 2012, as further described in Note 1A. Due to the extended recovery period, SCE&G is allowed to collect interest on the deferred balance.
In July 2009, SCE&G filed with the SCPSC requests for an order pursuant to the Base Load Review Act (the BLRA) to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station. The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below. The revised schedule does not change the previously announced completion date for the two nuclear units or the originally announced cost. The SCPSC has scheduled a hearing on this matter for November 4, 2009, and is expected to issue an order in January 2010.
In June 2009, SCE&G filed a request with the SCPSC for approval of certain demand reduction and energy efficiency programs (DSM programs). SCE&G has requested the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM programs along with an incentive for investing in such programs. The SCPSC is expected to conduct a hearing on SCE&G’s request in January 2010.
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 proposed construction by SCE&G and the South Carolina Public Service Authority (Santee Cooper) to build and operate two new nuclear generating units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement and construction contract under which they will be built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with the schedules, estimates and projections, including contingencies set forth in the approved application. As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009. In addition, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments would be based on SCE&G’s updated cost of debt and capital structure and on an allowed
return on common equity of 11%. In May 2009, two intervenors filed separate appeals of the order with the South Carolina Supreme Court. The appeals are pending, and SCE&G cannot predict how or when they will be resolved. In September 2009, the SCPSC approved SCE&G’s first annual revised rate request under the BLRA. The $22.5 million or 1.1% increase to retail electric rates is effective for bills rendered on or after October 30, 2009.
In March 2008, SCE&G and Santee Cooper filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). This COL application for the two new units was reviewed for completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC issued a 30-month review schedule from the docketing date to the issuance of the safety evaluation report which would signify satisfactory completion of its review. Both the environmental and safety reviews by the NRC are in progress and should support a COL issuance in late 2011. This date would support both the project schedule and the substantial completion dates for the two new units in 2016 and 2019, respectively.
In June 2009, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas base rates of 2.53% under the terms of the Natural Gas Rate Stabilization Act (Stabilization Act). The Stabilization Act is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. In October 2009, the SCPSC approved an increase in retail natural gas base rates of $13 million. The rate adjustment will be implemented with the first billing cycle of November 2009.
In October 2008, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $3.7 million under the terms of the Stabilization Act. The rate adjustment was effective with the first billing cycle of November 2008.
SCE&G’s tariffs include a purchase gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G's rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. In August 2008, in connection with the annual review of the PGA and the gas purchasing policies of SCE&G, the SCPSC determined that SCE&G’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended February 29, 2008. The next annual review is scheduled for November 2009.
PSNC Energy’s 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 Energy’s gas purchasing practices annually.
In October 2009, in connection with PSNC Energy’s 2009 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, 2009.
In September 2009, the NCUC approved PSNC Energy’s semi-annual rate adjustment under the Customer Usage Tracker (CUT). The CUT allows PSNC Energy to adjust its base rates for residential and commercial customers based on average per customer consumption. As a result of this rate adjustment, increases for residential and commercial customers are in effect for service rendered on and after October 1, 2009. The previous semi-annual rate adjustment under the CUT, which was effective for service rendered from April 1 through September 30, 2009, resulted in rate decreases.
In October 2008, the NCUC granted PSNC Energy an annual increase in natural gas margin revenues of approximately $9.1 million, offset by an $8.4 million reduction in fixed gas costs, for a net annual increase in rates and charges to customers of approximately $0.7 million. The new rates were effective for services rendered on or after November 1, 2008.
3. LONG-TERM DEBT AND LIQUIDITY
In September 2009, PSNC Energy entered into an agreement to issue and sell $100 million of ten-year unsecured notes. PSNC Energy has until March 31, 2010 to draw funds on the notes.
In June 2009, SCANA issued $30 million of Floating Rate Senior Notes due June 1, 2034. This final installment of notes, together with notes in the same series previously issued in 2007 and 2008, represents total borrowings in the series of $110 million principal amount. Proceeds from these notes were used to finance capital expenditures and for general corporate purposes.
In March 2009, SCE&G issued $175 million of First Mortgage Bonds bearing an annual interest rate of 6.05% and maturing on January 15, 2038. Proceeds from the sale were used to repay short-term debt and for general corporate purposes.
Substantially all of SCE&G's and South Carolina Generating Company, Inc.’s (GENCO) 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 South Carolina Fuel Company, Inc. (Fuel Company)) and PSNC Energy had available the following committed lines of credit (LOC), and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
(a) Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of
LOC advances or short-term commercial paper.
(b) SCE&G, Fuel Company and PSNC Energy may issue commercial paper in the amounts of up to $350 million, $250
million and $250 million, respectively.
The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wachovia Bank, National Association and Bank of America, N.A. each provide 14.3% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%. Four other banks provide the remaining 9.6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company) 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 SCE&G (including Fuel Company) and PSNC Energy. In addition, a portion of the credit facilities supports SCANA’s borrowing needs.
4. COMMON EQUITY
On January 7, 2009, SCANA closed on the sale of 2.875 million shares of common stock at $35.50 per share. Net proceeds of $100.5 million were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes. In addition, SCANA issued common stock valued at $68.0 million (when issued) during the nine months ended September 30, 2009 through various compensation and dividend reinvestment plans.
5. DERIVATIVE FINANCIAL INSTRUMENTS
The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings or as a component of other comprehensive income (loss), depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cashflow models with independently sourced data.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. SCANA's Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure. The Risk Management Committee, which is comprised of certain officers, including the
Company's Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
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 New York Mercantile Exchange (NYMEX) futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.
The Company’s regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of 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. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. These derivative financial instruments utilized by the Company’s regulated gas operations are not designated as hedges.
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 deferred 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, SCANA Energy Marketing, Inc. (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 classified 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. Some of these swaps were terminated prior to maturity of the underlying debt instruments. The gains on these swaps, which were terminated at various times prior to 2006, 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. These arrangements 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 if for the holding company or nonregulated subsidiaries, are recorded in other comprehensive income. Ineffective portions are recognized in income.
The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the consolidated statements of cash flows.
Quantitative Disclosures Related to Derivatives
At September 30, 2009, the Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes an aggregate 14,240,162 dekatherms related to basis swap contracts in Retail Gas Marketing and Energy Marketing.
At September 30, 2009, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $9.6 million and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $331.4 million.
(b) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses. In the
Company’s condensed consolidated balance sheet, unrealized gain and loss positions with the same counterparty are reported as
either a net asset or liability.
The effect of derivative instruments on the statements of income for the three and nine months ended September 30, 2009 is as follows:
Derivatives in Fair Value Hedging Relationships
The Company’s interest rate swaps designated as fair value hedges, including the amortization of gains on those terminated prior to 2006 discussed above, resulted in reductions to interest expense of $1.3 million and $4.0 million for the three and nine months ended September 30, 2009, respectively.
Derivatives in Cash Flow Hedging Relationships
As of September 30, 2009, 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 $10.2 million as an increase to gas cost and approximately $2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of September 30, 2009, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2013.
Other gains (losses) recognized in income representing interest rate hedge ineffectiveness were $(0.8) million and $1.2 million, net of tax, for the three and nine months ended September 30, 2009, respectively. These amounts are recorded within interest expense on the statement of income.
Credit Risk Considerations
Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2009, the Company has posted $16.7 million 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 September 30, 2009, the Company would be required to post an additional $21.3 million 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 September 30, 2009, is $38.0 million.
6. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using discounted cashflow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
There were no fair value measurements based on significant unobservable inputs (Level 3) for either date presented.
The financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2009 and December 31, 2008 were as follows:
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. Early settlement of long-term debt may not be possible or may not be considered prudent.
The fair value of preferred stock is estimated using market quotes.
Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.
7. COMMITMENTS AND CONTINGENCIES
Commitments and contingencies at September 30, 2009 include the following:
A. Nuclear Insurance
The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.5 billion. Each reactor licensee is currently liable for up to $117.5 million per reactor owned by such licensee for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be $78.3 million per incident, but not more than $11.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.2 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses, including replacement power, 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’s rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident.
However, if such an incident were to occur, it would have a material adverse impact on the Company’s results of operations, cash flows and financial position.
The United States Environmental Protection Agency (EPA) issued a final rule in 2005 known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances. On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it. Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements. SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction and SCE&G and GENCO are installing wet limestone scrubbers at Wateree and Williams Stations for sulfur dioxide reduction. The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these scrubber projects. The Company cannot predict when the EPA will issue a revised rule or what impact the rule will have on SCE&G and GENCO. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.
On April 17, 2009 the EPA issued a proposed finding that atmospheric concentrations of greenhouse gasses endanger public health and welfare within the meaning of Section 202(a) of the Clean Air Act. The proposed finding, as finalized, enables the EPA to regulate greenhouse gas emissions under the Clean Air Act. On September 30, 2009, the EPA issued a proposed rule that would require large facilities emitting over 25,000 tons of greenhouse gases (GHG) a year (such as SCE&G) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions. The Company expects that any costs incurred to comply with greenhouse gas emission requirements will be recoverable through rates.
SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessment and cleanup costs and recovers them through rates (see Note 1).
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by the South Carolina Department of Health and Environmental Control. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $9.3 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites, net of insurance recovery,
through rates. At September 30, 2009, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $19.3 million.
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. PSNC Energy has recorded a liability and associated regulatory asset of $4.4 million, which reflects its estimated remaining liability at September 30, 2009. PSNC Energy expects to recover through rates any costs, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.
The Company is also engaged in various other environmental matters incidental to its business operations which management anticipates will be resolved without a material adverse impact on the Company’s results of operations, cash flows or financial condition.
C. Claims and Litigation
In May 2004, a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims. SCANA and SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. In June 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to owners of easements situated in Charleston County, South Carolina. In February 2008 the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County. In July 2008, the plaintiff’s motion to add SCANA Communications, Inc. (SCI) to the lawsuit as an additional defendant was granted. Trial is not anticipated before the summer of 2010. SCANA, SCI and SCE&G will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material adverse impact on the Company’s results of operations, cash flows or financial condition.
D. Nuclear Generation
In May 2008, SCE&G and Santee Cooper announced that they had entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station. SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the two additional 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 and state approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, the second in 2019. SCE&G’s share of the estimated cash outlays (future value) totals $6.5 billion for plant costs and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.
8. SEGMENT OF BUSINESS INFORMATION
The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations, Gas Distribution and Gas Transmission 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.