10-Q 1 form10-q3.txt FORM 10-Q ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from to ------------ ----------------------- Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. 1-8809 SCANA Corporation 57-0784499 (a South CarolinaCorporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-3375 South Carolina Electric & Gas Company 57-0248695 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-11429 Public Service Company of North Carolina, Incorporated 56-2128483 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 Indicate by check mark whether the registrants: (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the last practicable date. Description of Shares Outstanding Registrant Common Stock at October 31, ---------- ------------ ---------------- 2001 SCANA Corporation Without Par Value 104,728,268 South Carolina Electric & Gas Company Par Value $4.50 Per Share 40,296,147(a) Public Service Company of North Carolina, Incorporated Without Par Value 1,000(a) (a)Held beneficially and of record by SCANA Corporation. This combined Form 10-Q is separately filed by SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated. 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 companies. Public Service Company of North Carolina, Incorporated 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). =============================================================================== INDEX Page PART I. FINANCIAL INFORMATION SCANA Corporation Financial Section..........................................3 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of September 30, 2001 and December 31, 2000.............................................4 Condensed Consolidated Statements of Income and Retained Earnings for the Periods Ended September 30, 2001 and 2000........6 Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2001 and 2000.........................7 Condensed Consolidated Statements of Comprehensive Income...........8 Notes to Condensed Consolidated Financial Statements................9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................................19 Item 3. Quantitative and Qualitative Disclosures About Market Risk.........27 South Carolina Electric & Gas Company Financial Section.....................28 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of September 30, 2001 and December 31, 2000............................................29 Condensed Consolidated Statements of Income and Retained Earnings for the Periods Ended September 30, 2001 and 2000.......31 Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2001 and 2000................................32 Notes to Condensed Consolidated Financial Statements...............33 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................39 Item 3. Quantitative and Qualitative Disclosures About Market Risk.........43 Public Service Company of North Carolina, Incorporated Financial Section....44 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of September 30, 2001 and December 31, 2000............................................45 Condensed Consolidated Statements of Income (Loss) and Retained Earnings (Deficit) the Periods Ended September 30, 2001 and 2000................................................46 Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2001 and 2000................................47 Notes to Condensed Consolidated Financial Statements...............48 Item 2. Management's Narrative Analysis of Results of Operations...........52 PART II. OTHER INFORMATION Item 1. Legal Proceedings..................................................54 Item 6. Exhibits and Reports on Form 8-K...................................54 Signatures..................................................................55 Exhibit Index...............................................................58 SCANA CORPORATION FINANCIAL SECTION PART I. FINANCIAL INFORMATION Item 1. Financial Statements
SCANA CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) ---------------------------------------------------------------------------------- ------------------ September 30, December 31, Millions of dollars 2001 2000 ---------------------------------------------------------------------------------- ------------------ Assets Utility Plant: Electric $4,842 $4,747 Gas 1,481 1,435 Other 187 187 --------------------------------------------------------------------------------- ------------------ Total 6,510 6,369 Less accumulated depreciation and amortization 2,338 2,212 ---------------------------------------------------------------------------------- ------------------ Total 4,172 4,157 Construction work in progress 396 261 Nuclear fuel, net of accumulated amortization 49 57 Acquisition adjustments, net of accumulated amortization 463 474 ---------------------------------------------------------------------------------- ------------------ Utility Plant, Net 5,080 4,949 ---------------------------------------------------------------------------------- ------------------ Nonutility Property, net of accumulated depreciation 108 79 Investments 204 203 ---------------------------------------------------------------------------------- ------------------ ---------------------------------------------------------------------------------- ------------------ Nonutility Property and Investments, Net 312 282 ---------------------------------------------------------------------------------- ------------------ ---------------------------------------------------------------------------------- ------------------ Current Assets: Cash and temporary investments 142 159 Receivables (net of allowance for uncollectible accounts of $33 in 2001 and $31 in 2000) 394 699 Inventories (at average cost): Fuel 162 107 Materials and supplies 59 56 Emission allowances 15 20 Prepayments 19 16 Investments 609 479 ---------------------------------------------------------------------------------- ------------------ Total Current Assets 1,400 1,536 ---------------------------------------------------------------------------------- ------------------ Deferred Debits: Environmental 36 30 Nuclear plant decommissioning fund 77 72 Pension asset, net 228 196 Other regulatory assets 205 213 Other 202 142 ---------------------------------------------------------------------------------- ------------------ Total Deferred Debits 748 653 ---------------------------------------------------------------------------------- ------------------ Total $7,540 $7,420 ================================================================================== ==================
SCANA CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) --------------------------------------------------------------------------------- ----------------- September 30, December 31, Millions of dollars 2001 2000 --------------------------------------------------------------------------------- ----------------- Capitalization and Liabilities Stockholders' Investment: Common Equity $2,131 $2,032 Preferred stock (Not subject to purchase or sinking funds) 106 106 --------------------------------------------------------------------------------- ----------------- Total Stockholders' Investment 2,237 2,138 Preferred Stock, net (Subject to purchase or sinking funds) 10 10 SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of the 7.55% Junior Subordinated Debentures of SCE&G, due 2027 50 50 Long-Term Debt, net 2,671 2,850 --------------------------------------------------------------------------------- ----------------- Total Capitalization 4,968 5,048 --------------------------------------------------------------------------------- ----------------- Current Liabilities: Short-term borrowings 75 398 Current portion of long-term debt 738 41 Accounts payable 159 394 Customer deposits 27 27 Taxes accrued 76 54 Interest accrued 60 42 Dividends declared 34 32 Deferred income taxes, net 148 98 Other 23 30 --------------------------------------------------------------------------------- ----------------- Total Current Liabilities 1,340 1,116 --------------------------------------------------------------------------------- ----------------- Deferred Credits: Deferred income taxes, net 702 721 Deferred investment tax credits 115 119 Reserve for nuclear plant decommissioning 77 72 Postretirement benefits 119 113 Other regulatory liabilities 91 70 Other 128 161 --------------------------------------------------------------------------------- ----------------- Total Deferred Credits 1,232 1,256 --------------------------------------------------------------------------------- ----------------- Total $7,540 $7,420 ================================================================================= ================= See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS (Unaudited) ----------------------------------------------------------------------- ----------------------------- ------------------------------ Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars, except per share amounts 2001 2000 2001 2000 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Operating Revenues: Electric $416 $397 $1,097 $1,011 Gas - Regulated 133 159 775 635 Gas - Nonregulated 161 260 897 654 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Total Operating Revenues 710 816 2,769 2,300 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Operating Expenses: Fuel used in electric generation 87 84 222 228 Purchased power 43 19 131 36 Gas purchased for resale 235 366 1,383 1,023 Other operation and maintenance 117 118 367 346 Depreciation and amortization 56 54 168 162 Other taxes 29 29 88 88 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Total Operating Expenses 567 670 2,359 1,883 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Operating Income 143 146 410 417 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Other Income: Other income, including allowance for equity funds used during construction 12 9 43 27 Gain on sale of assets 1 1 11 2 Gain on sale of investment - - 545 - ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Total Other Income 13 10 599 29 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 156 156 1,009 446 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction 52 58 173 167 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 104 98 836 279 Income Taxes 38 36 300 108 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 66 62 536 171 Preferred Dividend Requirement of SCE&G - Obligated Mandatorily Redeemable Preferred Securities (1) (3) (3) (1) ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Income Before Cash Dividends on Preferred Stock of Subsidiary and Cumulative Effect of Accounting Change 65 61 533 168 Cash Dividends on Preferred Stock of Subsidiary (At stated rates) (2) (2) (6) (6) ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Income Before Cumulative Effect of Accounting Change 63 59 527 162 Cumulative Effect of Accounting Change, net of taxes (Note 2) - - - 29 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Net Income 63 59 527 191 Retained Earnings at Beginning of Period 1,251 792 850 720 Common Stock Cash Dividends Declared (31) (30) (94) (90) ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Retained Earnings at End of Period $1,283 $821 $1,283 $821 ======================================================================= ============== ============== =============== ============== Basic and Diluted Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $.61 $.56 $5.03 $1.55 Cumulative Effect of Accounting Change, net of taxes - - - .28 ----------------------------------------------------------------------- -------------- -------------- --------------- -------------- Basic and diluted earnings per share $.61 $.56 $5.03 $1.83 ======================================================================= ============== ============== =============== ============== Weighted average shares outstanding (millions) 104.7 104.7 104.7 104.5 See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) --------------------------------------------------------------------------------------- ---------------------------------- Nine Months Ended September 30, --------------------------------------------------------------------------------------- ---------------------------------- Millions of dollars 2001 2000 --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Operating Activities: Net income $527 $191 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - (29) Depreciation and amortization 174 180 Amortization of nuclear fuel 11 15 Gain on sale of assets and investments (556) (2) Hedging activities (95) - Excess distributions (undistributed earnings) of affiliates, net 3 (3) Preferred stock dividends of subsidiary 6 6 Allowance for funds used during construction (16) (6) Over (under) collection, fuel adjustment clauses 17 4 Changes in certain assets and liabilities: (Increase) decrease in receivables 299 31 (Increase) decrease in inventories (53) (24) (Increase) decrease in pension asset (32) (33) (Increase) decrease in other regulatory assets (2) 11 Increase (decrease) in deferred income taxes, net 210 17 Increase (decrease) in regulatory liabilities 18 6 Increase (decrease) in postretirement benefits 6 14 Increase (decrease) in accounts payable (235) (27) Increase (decrease) in taxes accrued 22 (35) Other, net (34) 13 --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Provided From Operating Activities 270 329 --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (311) (204) Purchase of subsidiary, net of cash acquired - (212) Proceeds from sale of assets 28 1 Increase in nonutility property (35) (16) Increase in investments (43) (16) --------------------------------------------------------------------------------------- ------------------ --------------- --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Used For Investing Activities (361) (447) --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 149 148 Issuance of notes and loans 654 998 Repayments and repurchases: First Mortgage Bonds - (100) Notes and loans (308) (174) Common stock - (488) Dividend payments: Common stock (92) (94) Preferred stock of subsidiary (6) (6) Short-term borrowings, net (323) (140) --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Provided From Financing Activities 74 144 --------------------------------------------------------------------------------------- ------------------ --------------- Net Increase (Decrease) In Cash and Temporary Investments (17) 26 Cash and Temporary Investments, January 1 159 116 --------------------------------------------------------------------------------------- ------------------ --------------- Cash and Temporary Investments, September 30 $142 $142 ======================================================================================= ================== =============== Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $8 for 2001 and $4 for $162 $134 2000) - Income taxes 41 109 Noncash Investing and Financing Activities: Unrealized loss on securities available for sale, net of tax (294) (132) In conjunction with the February 2000 acquisition of Public Service Company of North Carolina, Incorporated, liabilities were assumed as follows: Fair value of assets acquired $1,177 Cash paid for capital stock (212) Stock issued for consideration (488) --------- Liabilities assumed $477 ========= See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) ----------------------------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars 2001 2000 2001 2000 ------------------------------------------------------------------- ---------- ------------- Net Income $63 $59 $527 $191 Other Comprehensive Income (Loss), net of tax: Unrealized gains (losses) on securities available for sale (195) (20) (294) (132) Unrealized gains (losses) on hedging activities (10) - (40) - --------------------------------------------------------------------------------- ------------- Total Comprehensive Income (1) $(142) $39 $193 $59 ================================================================================= =============
(1) Accumulated other comprehensive income (loss) of the Company totaled $(195) million and $139 million as of September 30, 2001 and December 31, 2000, respectively. See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS September 30, 2001 (Unaudited) The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for the year ended December 31, 2000. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature except as described in Notes 2, 3 and 4, which are necessary for a fair statement of the results for the interim periods reported. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Basis of Accounting The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71. This accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of September 30, 2001, approximately $241 million and $91 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $140 million and $70 million, respectively. The electric and gas regulatory assets of approximately $61 million and $40 million, respectively, (excluding deferred income tax assets) are recoverable through rates. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 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 in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected. B. New Accounting Standards On January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. See Note 7 for a discussion of the impact of the Company's adoption of SFAS 133. In June 2001 the Financial Accounting Standards Board approved the issuance of three new accounting standards. SFAS 141, "Business Combinations," requires that all business combinations be accounted for using the purchase method of accounting. SFAS 141 applies to all business combinations initiated after June 30, 2001, and is not expected to have any impact on the Company's results of operations, cash flows or financial position. SFAS 142, "Goodwill and Other Intangible Assets," requires that goodwill not be amortized but instead be tested for impairment at least annually at the reporting unit level. A reporting unit is the same level as, or one level below, an operating segment. The Company will adopt SFAS 142 effective January 1, 2002. The impact SFAS 142 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. C. Stock Option Plan On April 27, 2000 the Company adopted the SCANA Corporation Long-Term Equity Compensation Plan (the Plan). Under the Plan, certain employees and non-employee directors may receive nonqualified stock options and other forms of equity compensation. The Company accounts for this equity-based compensation under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25), and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation." As of September 30, 2001 options to acquire approximately 877,000 shares of SCANA common stock have been granted under the Plan at strike prices equal to or greater than market prices on the dates of grant. Therefore, no compensation expense has been recorded. D. Earnings Per Share Earnings per share amounts have been computed in accordance with SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed as net income divided by the weighted average number of shares of common stock outstanding during the period 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. E. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2001. 2. Cumulative Effect of Accounting Change Effective January 1, 2000 the Company changed its method of accounting for operating revenues associated with its regulated utility operations from cycle billing to full accrual. The cumulative effect of this change was $29 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. 3. ACQUISITION On February 10, 2000 the Company completed its acquisition of Public Service Company of North Carolina, Incorporated (PSNC) in a business combination accounted for as a purchase. PSNC became a wholly owned subsidiary of the Company. PSNC is a public utility engaged primarily in transporting, distributing and selling natural gas to approximately 363,000 residential, commercial and industrial customers in 26 of its 28 franchised counties in North Carolina. Pursuant to the Agreement and Plan of Merger, PSNC shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. In connection with the acquisition, 16.3 million shares of SCANA common stock were repurchased for approximately $488 million. The results of operations of PSNC are included in the accompanying financial statements as of January 1, 2000, the effective date of acquisition. The total cost of the acquisition was approximately $700 million, which exceeded the fair value of the net assets acquired by approximately $466 million. The excess is being amortized over 35 years on a straight-line basis. 4. RATE AND OTHER REGULATORY MATTERS South Carolina Electric & Gas Company A. On April 24, 2001 the Public Service Commission of South Carolina (PSC) approved South Carolina Electric & Gas Company's (SCE&G) request to increase the fuel component of rates charged to electric customers from 1.330 cents per kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2001 through April 2002. The increase also provides recovery over a two-year period of under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2001. B. On July 20, 2000 the PSC approved SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. As part of its regularly scheduled annual review of gas costs, the PSC issued an order on November 9, 2000 which further increased the cost of gas component to 78.151 cents per therm, effective with the first billing cycle in November 2000. On December 21, 2000 the PSC issued an order approving SCE&G's request for another out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. On March 9, 2001 the PSC issued an order granting SCE&G's request to reduce the cost of gas component to 79.340 cents per therm, effective with the first billing cycle in March 2001. On October 23, 2001, as part of the annual review of gas costs, the PSC approved SCE&G's request to further reduce the cost of gas component to 59.646 cents per therm effective with the first billing cycle in November 2001. C. On July 5, 2000 the PSC approved SCE&G's request to implement lower depreciation rates for its gas operations. The new rates were effective retroactively to January 1, 2000 and resulted in a reduction in annual depreciation expense of approximately $2.9 million. The retroactive effect was recorded in the second quarter of 2000. D. On September 14, 1999 the PSC approved an accelerated capital recovery plan for SCE&G's Cope Generating Station. The plan was implemented beginning January 1, 2000 for a three-year period. The PSC approved an accelerated capital recovery methodology wherein SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates. The amount of the accelerated depreciation will be determined by SCE&G based on the level of revenues and operating expenses, not to exceed $36 million annually without the approval of the PSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. As of September 30, 2001 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. E. On January 9, 1996 the PSC issued an order granting SCE&G an increase in retail electric rates which was fully implemented by January 1997. The PSC authorized a return on common equity of 12.0 percent. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated amortization of a significant portion of SCE&G's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, which enabled SCE&G to recover the balances as of the end of the year 2000. F. In 1994 the PSC issued an order approving SCE&G's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants (MGPs). The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In October 2001, as a result of the annual review, the PSC approved SCE&G's request to increase the billing surcharge from $1.1cents per therm to $3.0 cents per therm, which is intended to provide for the recovery of the balance remaining at September 30, 2001 of $25.9 million prior to the end of the year 2005. Public Service Company of North Carolina, Incorporated G. PSNC's rates are established using a benchmark cost of gas approved by the North Carolina Utilities Commission (NCUC) which may be modified periodically to reflect changes in the commodity price of natural gas purchased by PSNC. PSNC may file revised tariffs with the NCUC coincident with these changes or it may track the changes in its deferred accounts for subsequent rate consideration. The rules of the NCUC allow recovery of all prudently incurred gas costs. The NCUC reviews PSNC's gas purchasing practices annually. PSNC's benchmark cost of gas in effect during the nine months ended September 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date -------------- -------------- -------------- -------------- $.690 January 2001 $.300 January 2000 $.750 February-March 2001 $.265 February-May 2000 $.650 April-August 2001 $.350 June 2000 $.500 September 2001 $.450 July-September 2000 H. On April 6, 2000 the NCUC issued an order permanently approving PSNC's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. This mechanism allows PSNC to collect from its customers amounts approximating the amounts paid for natural gas. I. A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from PSNC's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On December 30, 1999 PSNC filed an application with the NCUC to extend natural gas service to Madison, Jackson and Swain Counties, North Carolina. Pursuant to state statutes, the NCUC required PSNC to forfeit its exclusive franchises to serve six counties in western North Carolina effective January 31, 2000 because these counties were not receiving any natural gas service. Madison, Jackson and Swain Counties were included in the forfeiture order. On June 29, 2000 the NCUC approved PSNC's requests for reinstatement of its exclusive franchises for Madison, Jackson and Swain Counties and disbursement of up to $28.4 million from PSNC's expansion fund for this project. PSNC estimates that the cost of this project will be approximately $31.4 million. The Madison County portion of the project was completed at a cost of approximately $5.7 million, and customers began receiving service in July 2001. J. On December 7, 1999 the NCUC issued an order approving SCANA's acquisition of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately $1 million in each of August 2000 and August 2001, and has agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events. 5. LONG-TERM DEBT On January 24, 2001 SCANA issued $202 million two-year floating rate notes maturing on January 24, 2003. The interest rate is reset quarterly based on three-month LIBOR plus 110 basis points. Also, on January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. On February 16, 2001 PSNC issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. The proceeds from these borrowings were used to reduce short-term debt and for general corporate purposes. On May 9, 2001 SCANA issued $300 million medium-term notes maturing May 15, 2011 and bearing a fixed interest rate of 6.875 percent (see Note 7). The proceeds were used to refinance $300 million bank notes originally issued to consummate SCANA's acquisition of PSNC. 6. RETAINED EARNINGS The Company's Restated Articles of Incorporation do not limit the dividends that may be payable on its common stock. However, the Restated Articles of Incorporation of SCE&G and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At September 30, 2001 approximately $36 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock. 7. FINANCIAL INSTRUMENTS Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires the Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in the fair value of derivative instruments are either recognized in earnings or reported as a component of other comprehensive income, depending upon the intended use of the derivative and the resulting designation. 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 price market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as New York Mercantile Exchange futures contracts or options and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions. These instruments do not constitute investments independent of the hedged exposures. Risk limits are established to control the level of market, credit, liquidity and operational/administrative risks assumed by the Company. The Company's Board of Directors has delegated the authority for setting market risk limits to the Risk Management Committee, which is comprised of members of senior management, the Company's Controller, the Senior Vice President of South Carolina Pipeline Corporation and the President of SCANA Energy Marketing, Inc. The Risk Management Committee provides assurance to the Board of Directors with regard to compliance with risk management policies and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are prohibited as well as the authorization requirements for transactions that are allowed. As a result of adopting SFAS 133, the Company recorded a credit of approximately $23.0 million, net of tax, as the effect of a change in accounting principle (transition adjustment) to other comprehensive income on January 1, 2001. This amount represents the reclassification of unrealized gains that were deferred and reported as liabilities at December 31, 2000. All gains/losses related to qualifying cash flow hedges so reflected in other comprehensive income will be reclassified to earnings at the time the hedged transaction affects earnings. The Company recognized losses of approximately $7.4 million and $2.8 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and nine months ended September 30, 2001, respectively. In May 2001 the Company entered into an interest rate swap agreement to pay variable rate and receive fixed rate interest payments on a notional amount of $300 million. This swap was designated as a fair value hedge of the $300 million medium-term notes also issued in May. The swap agreement was terminated and replaced with another swap agreement, also designated as a fair value hedge, in August 2001. At September 30, 2001 the estimated fair value of this swap was $16.5 million. In August 2001 the Company received a net premium of $6.5 million to terminate the original swap. This amount is being amortized over the ten year term of the $300 million medium-term notes. 8. INVESTMENTS IN EQUITY SECURITIES At September 30, 2001 SCANA and SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, held the following investments: o SCH owns approximately 39.3 million ordinary shares of Deutsche Telekom AG (DT), a European telecommunications carrier. These shares were received in exchange for the approximately 14.9 million shares of Powertel, Inc. (Powertel) SCH owned prior to DT's acquisition of Powertel in May 2001. SCH recorded a non-cash, after-tax gain of $354.4 million as a result of the exchange. Based on the value of DT ordinary shares on the date of the exchange, SCH's investment in DT is approximately $798.0 million. DT ordinary shares closed at $15.50 per share on September 30, 2001, resulting in a pre-tax unrealized holding loss of $188.7 million. Accumulated other comprehensive income includes the after-tax amount of unrealized holding gains and losses on ordinary shares. o ITC Holding Company, Inc. (ITC) holds ownership interests in several Southeastern communications companies. SCH owns approximately 3.1 million common shares, 645,153 series A convertible preferred shares, and 133,664 series B convertible preferred shares of ITC. These investments cost approximately $5.8 million, $7.2 million, and $4.0 million, respectively. The market values of these investments are not readily determinable. o SCH owns approximately 5.1 million common shares of ITCD at a cost of approximately $43.0 million. ITCD common stock closed at $1.20 per share on September 30, 2001, resulting in a pre-tax unrealized holding loss of $36.9 million. In addition, SCH owns approximately 1.5 million shares of Series A preferred stock of ITCD, and SCANA owns 5,000 shares of Series B-1 and 6,667 shares of Series B-2 preferred stock of ITCD. These investments cost approximately $11.2 million, $4.3 million and $5.7 million, respectively. Series A preferred shares become convertible in March 2002 into approximately 3.0 million shares of ITCD common stock. Series B-1 and B-2 preferred shares are convertible at any time into a total of approximately 3.5 million shares of ITCD common stock. The market value of these series of preferred stock is not readily determinable. However, as converted, the market value of the underlying common stock was approximately $7.8 million at September 30, 2001, reflecting an unrealized pre-tax holding loss of approximately $13.4 million. In addition, the Company has warrants to purchase approximately 1.0 million shares of ITCD common stock, which cost approximately $1.7 million. At September 30, 2001 the value of these warrants was approximately $1.2 million, reflecting an unrealized pre-tax holding loss of approximately $0.6 million. Accumulated other comprehensive income includes the after-tax amount of these unrealized holding losses. o Knology, Inc. (Knology), an affiliate of ITC, is a broad-band service provider of cable television, telephone and internet services. SCH owns $71,050,000 face amount of 11.875 percent Senior Discount Notes due 2007 of Knology Broadband, Inc., a wholly-owned subsidiary of Knology. The Senior Discount Notes have a book basis at September 30, 2001 of approximately $63.1 million. In addition, SCH owns approximately 7.2 million shares of Knology series A convertible preferred stock with a cost basis of approximately $5.0 million and warrants to purchase approximately 159,000 shares of series A convertible preferred stock. On January 12, 2001 SCH invested $25.0 million for approximately 8.3 million shares of Knology series C convertible preferred stock. The market value of these investments is not readily determinable. 9. CONTINGENCIES With respect to commitments at September 30, 2001, reference is made to Note 13 of Notes to Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2000. Contingencies at September 30, 2001 include the following: A. Lake Murray Dam Reinforcement On October 15, 1999 the Federal Energy Regulatory Commission (FERC) notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. Construction for the project, which began in the third quarter of 2001 could cost up to $300 million with completion dates ranging from 2004 to 2006. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. B. Nuclear Insurance The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $9.5 billion. Each reactor licensee is currently liable for up to $88.1 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership of V. C. Summer Nuclear Station (Summer Station), would be approximately $58.7 million per incident, but not more than $6.7 million per year. SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit 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 $8.1 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'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 at Summer Station. If such an incident were to occur, it could have a material adverse impact on the Company's results of operations, cash flows and financial position. C. Environmental The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up 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 cleanup relate primarily to regulated operations. For SCE&G, such amounts are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.9 million at September 30, 2001. The deferral includes the estimated costs associated with the following matters. o In September 1992 the Environmental Protection Agency (EPA) notified SCE&G, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park area site in Charleston, South Carolina. This site encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of SCE&G's decommissioned MGPs, properties owned by the National Park Service and the City of Charleston and private properties. The site has not been placed on the National Priorities List, but may be added in the future. The Potentially Responsible Parties (PRPs) negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993, and the EPA approved a Remedial Investigation Report in February 1997 and a Feasibility Study Report in June 1998. In July 1998 the EPA approved SCE&G's Removal Action Work Plan for soil excavation. In September 1998 a Record of Decision was issued which sets forth the EPA's view of the extent of each PRP's responsibility for site contamination and the level to which the site must be remediated. In January 1999 the EPA issued a Unilateral Administrative Order for Remedial Design and Remedial Action directing SCE&G to design and carry out a plan of remediation for the Calhoun Park site. SCE&G submitted a Comprehensive Remedial Design Work Plan (RDWP) in December 1999 and proceeded with implementation pending agency approval. The RDWP was approved by the EPA in July 2000, and its implementation continues. In September 2000, SCE&G was notified by the South Carolina Department of Health and Environmental Control (DHEC) that benzene contamination was detected in the intermediate aquifer on surrounding properties to the Calhoun Park Area site. The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility Study on the intermediate aquifer, which was completed in June 2001. The EPA expects to issue a second Record of Decision dealing with the intermediate aquifer in the fourth quarter of 2001. As of September 30, 2001, SCE&G has spent approximately $14.8 million to remediate the Calhoun Park area site. Total remediation costs are estimated to be $21.9 million. o SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. For the site located in Sumter, effective September 15, 1998, SCE&G entered into a Remedial Action Plan Contract with DHEC pursuant to which it agreed to undertake a full site investigation and remediation under the oversight of DHEC. Site investigation, characterization and remediation are proceeding according to schedule. Excavation at the Sumter MGP site was completed in May 2001 as part of an Interim Removal Action. Further work may be required at the discretion of DHEC. Upon successful implementation of a site remedy, DHEC will give SCE&G a Certificate of Completion and a covenant not to sue. For the site located in Florence SCE&G entered into a similar Remedial Action Plan Contract with DHEC in September 2000. SCE&G is continuing to investigate the remaining site in Columbia, and is monitoring the nature and extent of residual contamination. In addition, PSNC owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. The North Carolina Department of Environment and Natural Resources (DENR) has recommended that no further action be taken with respect to one site. Excavation at the Raleigh MGP site was completed in March 2001 as part of an Interim Removal Action. Further work at this site may be required at the discretion of DENR. Work at the Durham MGP site began in May 2001 under a DENR-approved Phase II Workplan. An environmental due diligence review of PSNC conducted in February 1999 estimated that the cost to remediate the sites would range between $11.3 million and $21.9 million. During the second quarter of 2000, the review was finalized and the estimated liability was recorded. PSNC is unable to determine the rate at which costs may be incurred over this time period. The estimated cost range has not been discounted to present value. PSNC's associated actual costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. A May 1993 order by the NCUC authorized deferral accounting for all costs associated with the investigation and remediation of MGP sites. As of September 30, 2001 PSNC has recorded a liability and associated regulatory asset of $9.1 million, which reflects the minimum amount of the range, net of shared cost recovery expected from other PRPs and expenditures for work completed. Amounts incurred to date are approximately $1.1 million. Management intends to request recovery of additional MGP clean-up costs not recovered from other PRPs in future rate case filings, and believes that all costs incurred will be recoverable in gas rates. 10. 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 net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Affiliate revenue is derived from transactions between reportable segments as well as transactions between separate legal entities that are combined into the same reportable segment. Accumulated depreciation is not assignable to Electric Operations and Gas Distribution segments.
Disclosure of Reportable Segments (Millions of dollars) --------------------------- ----------- ------------- ------------- ----------- -------------- -------------- -------------- Three months ended Electric Gas Gas Retail Gas Energy Adjustments/ Consolidated September 30, 2001 Operations Distribution Transmission Marketing Marketing Eliminations Total --------------------------- ----------- ------------- ------------- ----------- -------------- -------------- -------------- External Revenue 416 90 43 116 45 - 710 Intersegment Revenue 163 1 33 - - (197) - Operating Income (Loss) 154 (14) 5 n/a n/a (2) 143 Net Income (Loss) n/a n/a n/a (2) - 65 63 Segment Assets 4,878 1,579 313 96 94 580 7,540 --------------------------- ----------- ------------ -------------- ----------- -------------- -------------- -------------- Nine months ended Electric Gas Gas Retail Gas Energy Adjustments/ Consolidated September 30, 2001 Operations Distribution Transmission Marketing Marketing Eliminations Total --------------------------- ----------- ------------ -------------- ----------- -------------- -------------- -------------- External Revenue 1,097 600 176 500 396 - 2,769 Intersegment Revenue 435 1 199 - - (635) - Operating Income 345 39 9 n/a n/a 17 410 Net Income n/a n/a n/a 5 5 517 527 Segment Assets 4,878 1,579 313 96 94 580 7,540 --------------------------- ----------- ------------ -------------- ----------- -------------- -------------- -------------- Three months ended Electric Gas Gas Retail Gas Energy Adjustments/ Consolidated September 30, 2000 Operations Distribution Transmission Marketing Marketing Eliminations Total --------------------------- ----------- ------------ -------------- ----------- -------------- -------------- -------------- External Revenue 397 97 62 112 148 - 816 Intersegment Revenue 152 1 41 - - (194) - Operating Income (Loss) 164 (11) 6 n/a n/a (13) 146 Net Income (Loss) n/a n/a n/a (5) (3) 67 59 Segment Assets 4,873 1,544 258 33 130 290 7,128 --------------------------- ----------- ------------ -------------- ----------- -------------- -------------- -------------- Nine months ended Electric Gas Gas Retail Gas Energy Adjustments/ Consolidated September 30, 2000 Operations Distribution Transmission Marketing Marketing Eliminations Total --------------------------- ----------- ------------ -------------- ----------- -------------- -------------- -------------- External Revenue 1,011 459 176 339 315 - 2,300 Intersegment Revenue 368 2 142 - - (512) - Operating Income 357 42 22 n/a n/a (4) 417 Net Income (Loss) n/a n/a n/a 1 (4) 1941 191 Segment Assets 4,873 1,544 258 33 130 290 7,128 1 Includes cumulative effect of accounting change (See Note 2).
11. SUBSEQUENT EVENT In November 2001 a non-public company in which the Company has invested approximately $7.8 million declared that it was insolvent. This company was in the microturbine generator business. The Company's investment, which consisted of convertible loans and convertible preferred stock, was written off in November 2001. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -------------------------------------------------------------------------------- SCANA CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for the year ended December 31, 2000. Statements included in this discussion and analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, including potential changes in the restructured, non-regulated Georgia natural gas markets, (3) changes in the economy, especially in areas served by the Company's subsidiaries, (4) the impact of competition from other energy suppliers, (5) growth opportunities for the Company's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in the Company's accounting policies, (8) weather conditions, especially in areas served by the Company's subsidiaries, (9) performance of and marketability of the Company's investments in telecommunications companies, (10) inflation, (11) changes in environmental regulations, (12) volatility in commodity natural gas markets and (13) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the Securities and Exchange Commission. The Company disclaims any obligation to update any forward-looking statements. LIQUIDITY AND CAPITAL RESOURCES SCANA Energy, the Company's non-regulated retail gas division in Georgia, has maintained its position as the second largest marketer in Georgia, with an approximate 27 percent market share. SCANA Energy lost approximately $ .02 per share in the quarter ended September 30, 2001, approximately $ .03 per share less than the loss reported for the corresponding period in 2000. See additional discussion at Results of Operations. Due to record high natural gas prices and cold winter temperatures, the Georgia Public Service Commission (GPSC) adopted emergency rules which prohibited gas marketers from disconnecting service to residential customers for non-payment from mid-January through March 2001. Customers were also permitted to switch marketers without first paying outstanding balances owed to their previous provider. As a result of this action, SCANA Energy increased its allowance for uncollectible accounts in the first quarter of 2001 and, to the extent permitted by other GPSC rules, has implemented more stringent credit policies. Since that time, the GPSC has remained extremely active in its review and oversight of the natural gas marketplace. In the summer of 2001, the GPSC placed restrictions on the length of time that customer deposits may be held by marketers and also called for other changes in the ways that marketers interact with their customers. Further, in September, Georgia's Governor called for the formation of a task force to study the impact of natural gas deregulation. These actions raise concern as to the level of additional restrictions which may be placed on marketers, including SCANA Energy, in the coming winter months and heighten the risks of SCANA Energy's business efforts in that market. SCANA Energy and SCANA's other natural gas distribution, transmission and marketing segments maintain gas inventory and also utilize forward contracts and financial instruments, including futures contracts, to manage their exposure to fluctuating commodity natural gas prices. (See also Note 7 of Notes to Condensed Consolidated Financial Statements and discussion at Item 3.) As a part of this risk management process, a portion of SCANA's projected natural gas needs for this winter has been purchased or otherwise placed under contract. This factor and others (e.g., the level of bad debts experienced) are, in the aggregate, used to establish retail pricing levels at SCANA Energy. As a result of the potential regulatory actions discussed above and other downward pricing pressures inherent in the competitive market, SCANA Energy may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability. On October 15, 1999 the Federal Energy Regulatory Commission (FERC) notified South Carolina Electric & Gas Company (SCE&G) of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. Construction for the project, which began in the third quarter of 2001, could cost up to $300 million with completion dates ranging from 2004 to 2006. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. On February 9, 2000 FERC issued FERC Order 2000. The Order required utilities which operate electric transmission systems to submit plans for the formation of regional transmission organizations (RTOs). In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth) as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In July 2001 FERC expressed its desire that utilities throughout the U. S. combine their transmission systems to create four large independent regional operators, one each in the Northeast, Southeast, Midwest and West. Accordingly, FERC ordered mediation talks to take place between the utilities forming GridSouth and certain groups that had proposed other RTOs. These talks were mediated by an administrative law judge, who issued her nonbinding mediation report to FERC in September 2001. The report made recommendations related to the formation of a Southeast regional RTO. FERC has not acted on the mediation report, and the timing or impact of future FERC orders related to RTOs cannot be predicted. In March 2001 V. C. Summer Nuclear Station returned to service. It had been taken out of service on October 7, 2000 for a planned maintenance and refueling outage. During initial inspection activities, plant personnel discovered a small leak coming from a hole in a weld in a primary coolant system pipe. Repairs were completed and the integrity of the new welds was verified through extensive testing. The Public Service Commission of South Carolina (PSC) has approved recovery of the cost of replacement power through SCE&G's electric fuel adjustment clause (see Note 4A of Notes to Condensed Consolidated Financial Statements). The Nuclear Regulatory Commission was closely involved throughout this process and approved SCE&G's actions to repair the crack, as well as the restart schedule. SCE&G will continue to monitor primary coolant system pipes during the next outage, scheduled for the spring of 2002. In March 2001 the Company completed the sale of its home security and alarm monitoring division (SCANA Security). The sale, valued at approximately $24.5 million, resulted in a one-time gain of approximately $.04 per share in the first quarter 2001 (see Results of Operations). In April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station returned to service. It had been taken out of service in January 2001 due to an electrical ground in the generator. The PSC has approved recovery of the cost of replacement power through SCE&G's electric fuel adjustment clause (see Note 4A of Notes to Condensed Consolidated Financial Statements). In June 2001 SCANA Communications, Inc. (SCI) agreed to subcontract the operation and maintenance of its 800 megahertz radio service network to Motorola for the period July 1, 2001 through March 31, 2002. After March 31, 2002 SCI has the option to sell the network to Motorola. In June 2001 South Carolina Pipeline Corporation (SCPC) announced that it will petition the PSC to allow SCPC to convert from a closed system to an open-access transportation-only system. Under an open access system customers would be required to secure their own gas supplies and interstate transportation services. SCPC plans to file the petition in the fall of 2001 and seek implementation in 2003. In July 2001 the Company announced the formation of SCG Pipeline, Inc., a wholly owned subsidiary that will engage in the transportation of natural gas in Georgia and South Carolina. SCG Pipeline will transport natural gas from interconnections with Southern Natural Gas and Southern LNG's Elba Island liquefied natural gas import terminal near Savannah, Georgia to an endpoint in Jasper County, South Carolina. SCG Pipeline plans to file for FERC certification in the first quarter of 2002. The proposed service date for the pipeline is November 2003. In addition SCPC announced plans to extend its existing facilities to interconnect with the proposed pipeline to gain access to additional supplies of natural gas. In October 2001 SCE&G filed with the PSC its siting plans to construct an 875 megawatt generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. Construction of the $450 million facility is expected to begin in April 2002, with commercial operation in the summer of 2004. In connection with the facility, SCE&G has signed a 250 megawatt electric supply contract with North Carolina Electric Membership Corporation for a term of at least five years beginning January 1, 2004. SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen built and operates a cogeneration facility in North Charleston, South Carolina. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court alleging that it incurred construction cost overruns relating to the facility and that the construction contract provides for recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were also named as defendants in the suit. Cogen filed a separate suit against the contractor for delay and performance issues. The suits were combined and the contractor brought the manufacturer of the generator into the performance suit. In November 2001 a settlement was reached between all parties. Terms of the settlement are confidential, but the settlement's impact on SCANA and SCE&G's results of operations, cash flow and financial position is not material. The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the nine months ended September 30, 2001 and 2000: -------------------------------------------------------------------------------- Nine Months Ended September 30, Millions of dollars 2001 2000 -------------------------------------------------------------------------------- Net cash provided from operating activities $270 $329 Net cash provided from financing activities 74 144 Cash provided from sale of assets 28 1 Cash and temporary investments available at the beginning of the period 159 116 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Net cash available for property additions and construction expenditures $531 $590 ================================================================================ Funds used for purchase of subsidiary $- $212 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $311 $204 Funds used for nonutility property additions $35 $16 ================================================================================ The Company's electric and natural gas businesses are seasonal in nature, with the primary demand for electricity being experienced during summer and winter and the primary demand for natural gas being experienced during winter. As a result of the significant increase during early 2001 and the latter half of 2000 in the cost to the Company of natural gas and the colder than normal weather experienced during winter 2000-2001, the Company experienced significant increases in its working capital requirements, contributing to the need for the financings by SCANA and PSNC in early 2001 as described below. On January 24, 2001 SCANA issued $202 million two-year floating rate notes maturing on January 24, 2003. The interest rate is reset quarterly based on three-month LIBOR plus 110 basis points. Also on January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. On February 16, 2001 PSNC issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. The proceeds from these borrowings were used to reduce short-term debt and for general corporate purposes. On May 9, 2001 SCANA issued $300 million medium-term notes maturing May 15, 2011 and bearing a fixed interest rate of 6.875 percent. SCANA also entered into an interest rate swap agreement, designated as a fair value hedge, to pay variable rate and receive fixed rate interest payments. The proceeds from the issuance of the medium-term notes were used to refinance $300 million of bank notes originally issued to consummate SCANA's acquisition of PSNC. The swap agreement was terminated and replaced with another swap agreement, also designated as a fair value hedge, in August 2001. The net premium of approximately $6.5 million received upon the original swap's termination is being amortized over the term of the associated debt. In October 2001 SCANA's shelf registration of an additional $302 million medium-term notes became effective. SCANA currently has a total of $800 million medium-term notes available for issuance. The Company anticipates that the remainder of its 2001 cash requirements will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. Sales of additional equity securities may also occur. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. The Company's ratio of earnings to fixed charges for the 12 months ended September 30, 2001 was 4.57. Environmental Matters For information on environmental matters see Note 9C of Notes To Condensed Consolidated Financial Statements. Investments SCANA and SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, hold investments in several telecommunications companies (described in Note 8 "Investments in Equity Securities" of Notes to Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q). As a result of Deutsche Telekom AG's (DT) acquisition of Powertel, Inc. (Powertel) on May 31, 2001, SCH's investment in Powertel was exchanged for approximately 39.3 million ordinary shares of DT. SCH may sell or transfer only up to 40% of these ordinary shares until November 30, 2001, after which time SCH may sell or transfer all of its DT shares. The Company intends to monetize SCH's investment in DT in an appropriate and timely manner and to use the proceeds to reduce outstanding debt and for potential future investments. In determining the book value of certain investments, the Company follows SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities" and related interpretive guidance in the SEC's Staff Accounting Bulletin No. 59. This guidance requires periodic assessment to determine if an other than temporary decline in value has occurred. If such a decline is identified, a write-down is required. The Company has determined that no write-down was required at September 30, 2001. The Company will continue to monitor and evaluate its investments for potential impairments. See Note 8 of Notes To Condensed Consolidated Financial Statements for a discussion of the Company's investments. In November 2001 a non-public company in which the Company has invested approximately $7.8 million declared that it was insolvent. This company was in the microturbine generator business. The Company's investment, which consisted of convertible loans and convertible preferred stock, was written off in November 2001. RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2001 AS COMPARED TO THE CORRESPONDING PERIODS IN 2000 Earnings and Dividends Earnings per share of common stock for the three and nine months ended September 30, 2001 and 2000 were as follows: -------------------------------------------------------------------------------- Three Months Ended Nine Months Ended 2001 2000 2001 2000 -------------------------------------------------------------------------------- Earnings derived from: Operations $.61 $.56 $1.61 $1.55 Non-recurring items: Realized gain from stock investment - - 3.38 - Sale of subsidiary assets - - .04 - Cumulative effect of change in accounting - - - .28 -------------------------------------------------------------------------------- Earnings per weighted average share $.61 $.56 $5.03 $1.83 ================================================================================ Earnings per share from operations for the three months ended September 30, 2001 increased $.05 as compared to 2000. The Company experienced an increase in gas margin of $.03, decreases in operation and maintenance expense of $.01 and interest expense of $.03, and other improvements of $.02. These improvements were partially offset by a decline in electric margin ($.04). Earnings per share from operations for the nine months ended September 30, 2001 increased $.06 as compared to 2000. The Company experienced increases in gas margin of $.14 and allowance for funds used during construction (AFC) of $.06, improved operating results due to the sale of SCANA Security of $.02, increased interest income of $.01 and other improvements of $.07. These improvements were partially offset by a decrease in electric margin ($.02) and increases in operation and maintenance expense ($.12), interest expense ($.06) and depreciation expense ($.04). For the last several years, the market value of the Company's retirement plan assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income for the three and nine months ended September 30, 2001 was $11.7 million and $31.0 million, compared to $13.2 million and $31.9 million for the corresponding periods in 2000. As a result of pension income, employee benefit expenses were reduced approximately $6.3 million and $16.7 million for the three and nine months ended September 30, 2001, compared to $7.4 million and $17.5 million for the corresponding periods in 2000. In addition, other income increased $3.6 million and $9.6 million for the three and nine months ended September 30, 2001 compared to $3.9 million and $9.9 million for the corresponding periods in 2000. The Company recognized a non-recurring gain of $3.38 per share in connection with the sale of its investment in Powertel, Inc., which was acquired by Deutsche Telekom AG in May 2001 (see Note 8 of Notes to Condensed Consolidated Financial Statements). The Company also recognized a gain of $.04 per share in connection with the sale of the assets of SCANA Security in March 2001. In 2000, earnings from the cumulative effect of change in accounting resulted from the recording of unbilled revenues by SCANA's regulated retail utility subsidiaries (see Note 2 of Notes to Condensed Consolidated Financial Statements). AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Both the equity and the debt portions of AFC are noncash items of nonoperating income which have the effect of increasing reported net income. AFC represented approximately seven percent and approximately two percent of income before taxes for the three months ended September 30, 2001 and 2000, respectively. AFC represented approximately two percent of income before income taxes for the nine months ended September 30, 2001 and 2000. The Company's Board of Directors declared the following quarterly dividends on common stock during 2001: ------------------------ -------------- --------------------- ------------------ Declaration Dividend Record Payment Date Per Share Date Date ------------------------ -------------- --------------------- ------------------ February 22, 2001 $.30 March 9, 2001 April 1, 2001 ------------------------ May 3, 2001 $.30 June 8, 2001 July 1, 2001 ------------------------ August 2, 2001 $.30 September 10, 2001 October 1, 2001 ------------------------ November 1, 2001 $.30 December 10, 2001 January 1, 2002 ------------------------ -------------- --------------------- ------------------ Electric Operations Electric Operations is comprised of the electric portion of SCE&G, South Carolina Generating Company (GENCO) and South Carolina Fuel Company (Fuel Company). Changes in the electric operations sales margins, including transactions with affiliates and excluding the cumulative effect of accounting change, for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
------------------------------------------------------------------------------------------------------------------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change ------------------------------------------------------------------------------------------------------------------- Electric operating revenue $416.3 $396.7 $19.6 4.9% $1,097.0 $1,010.8 $86.2 8.5% Less: Fuel used in generation 86.5 84.6 1.9 2.2% 221.7 227.5 (5.8) (2.5)% Purchased power 43.3 19.0 24.3 * 130.8 36.4 94.4 * -------------------------------------------------------------------------------- Margin $286.5 $293.1 $(6.6) (2.3)% $744.5 $746.9 $(2.4) (0.3)% =================================================================================================================== *Greater than 100%
Changes in electric operations sales margins for the three months ended September 30, 2001 reflect milder weather and an economic slowdown. Purchased power increased primarily due to power purchased for resale to other utilities. As a result, operating revenue also increased, but was more than offset by the effects of milder weather and the economic slowdown. Changes in electric operations sales margins for the nine months ended September 30, 2001 reflect steady customer growth partially offset by the effects of milder weather and the economic slowdown. Increases in purchased power costs for the nine months, as compared to the corresponding period in 2000, were primarily attributable to plant outages discussed at Liquidity and Capital Resources, which delayed scheduled maintenance outages at other plants until April and May 2001, and to the power purchased for resale in the third quarter. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC. Changes in the gas distribution sales margins, including transactions with affiliates and excluding the cumulative effect of accounting change, for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
------------------------------------------- --------- ---------- --------- --------- --------- ---------- ----------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change -------------------------------------------- --------- ------------------- --------- --------- ---------------------- Gas distribution operating revenue $90.3 $97.1 $(6.8) (7.0)% $600.8 $459.0 $141.8 30.9% Less: Gas purchased for resale 58.1 64.6 (6.5) (10.1)% 425.8 283.6 142.2 50.1% -------------------------------------------- -------- ---------- ---------- --------- ---------- Margin $32.2 $32.5 $(0.3) (0.9)% $175.0 $175.4 $(0.4) (0.2)% ============================================ ======== ========== ========= ========== ========= ========== ==========
Changes in gas distribution sales margin for the three and nine months ended September 30, 2001 reflect milder weather and an economic slowdown. For the nine months ended September 30, 2001, these factors were largely offset by customer growth. Revenues and purchases were impacted by large increases in natural gas prices in late 2000 and early 2001. Gas Transmission Gas Transmission is comprised of the operations of South Carolina Pipeline Corporation. Changes in the gas transmission sales margins, including transactions with affiliates, for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
------------------------------------------ --------- -------- ------------- ------- ---------- --------- ----------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change ------------------------------------------ ---------- --------------------- ------- --------- ---------------------- Gas transmission operating revenue $76.2 $102.9 $(26.7) (25.9)% $374.6 $318.6 $56.0 17.6% Less: Gas purchased for resale 63.6 89.5 (25.9) (28.9)% 342.3 276.1 66.2 24.0% ------------------------------------------ --------- ---------- -------- --------- --------- Margin $12.6 $13.4 $(0.8) (6.0)% $32.3 $42.5 $(10.2) (24.0)% ========================================== ========= ========== =========== ======== ========= ========= ===========
Gas transmission sales margins for the three and nine months ended September 30, 2001 decreased primarily as a result of an economic slowdown, reduced industrial margins due to the unfavorable competitive position of natural gas relative to alternate fuels, and the insolvency of an industrial customer in the first quarter of 2001. Revenues and purchases were impacted by large increases in natural gas prices in late 2000 and early 2001. Retail Gas Marketing Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's deregulated natural gas market. Retail gas marketing revenues and net income for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
---------------------------------- ----------- --------- --------- ----------- -------- --------- ---------- ----------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change ---------------------------------- ---------- ---------- --------------------- -------- --------- ---------------------- Operating revenues $116.0 $112.3 $3.7 3.3% $500.0 $339.2 $160.8 47.4% Net income (loss) $(8.5) $6.6 77.6% $4.8 $1.1 $3.7 * $(1.9) ================================== ========== =========== ========= ========== ========= ========= ========== ========== *Greater than 100%.
Operating revenues for the nine months ended September 30, 2001 increased primarily as a result of record high natural gas prices. Net income (loss) for the three and nine months improved primarily due to lower operating expenses. Energy Marketing Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Changes in energy marketing operating revenues, including transactions with affiliates, and net income (loss) for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
---------------------------------- --------- --------- ------- ----------- --------- ---------- ---- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change --------------------------------------- --------------- ---------- --------- -------------------- Operating revenues $45.1 $147.6 $(102.5) (69.4)% $396.7 $314.7 $82.0 26.1% Net income (loss) $(0.3) $0.3 $(0.6) * $4.8 $(4.1) $8.9 * ======================================= =================== =========== ========== ========= ========= *Greater than 100%
Operating revenues for the three months ended September 30, 2001 decreased as a result of phasing out marketing operations in the Midwest and California during the third quarter. Operating revenues for the nine months ended September 30, 2001 increased primarily as a result of record high natural gas prices and more favorable weather in early 2001, which was partially offset by phasing out marketing operations previously noted. Net income for the nine months ended September 30, 2001 increased primarily as a result of increased value in certain transportation contracts. Other Operating Expenses Changes in other operating expenses for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
----------------------------------------- ---------- --------- ---------- ---------- --------- ---------- --------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change ------------------------------------------ --------- -------------------- --------- --------- --------------------- Other operation and maintenance $116.6 $118.2 $(1.6) (1.4)% $367.7 $346.8 $20.9 6.0% Depreciation and amortization 56.4 53.8 2.6 4.8% 168.3 161.5 6.8 4.2% Other taxes 29.4 29.5 (0.1) (0.3)% 88.1 87.7 0.4 0.5% --------------------------------------- ---------- --------- ---------- --------- ---------- Total $202.4 $201.5 $0.9 0.4% $624.1 $596.0 $28.1 4.7% ========================================= ========== ========= ========== ========== ========= ========== =========
Other operation and maintenance expense for the nine months increased primarily as a result of increased revenue-related expenses (e.g., provision for bad debts) for energy sales and increased employee benefit costs. Depreciation and amortization for the three and nine months increased due to normal property additions. Other Income Other income for the nine months ended September 30, 2001 increased when compared to the corresponding period in 2000, primarily due to the non-recurring gain recognized in May 2001 in connection with the Company's investment in Powertel, Inc., which was acquired by Deutsche Telekom AG, and the March 2001 gain on the sale of the assets of SCANA Security (see Note 8 of Notes to Condensed Consolidated Financial Statements). Interest Expense Interest expense for the three months ended September 30, 2001 decreased when compared to the corresponding period in 2000 primarily due to declining variable interest rates. Interest expense for the nine months ended September 30, 2001 increased when compared to the corresponding period in 2000 primarily due to the issuance of debt in mid-2000 and early 2001. The proceeds of such debt offerings were used to refinance debt related to the acquisition of PSNC in February 2000 and for general corporate purposes, including providing working capital for natural gas purchases. Income Taxes Income taxes for the nine months ended September 30, 2001 increased approximately $191.8 million when compared to the corresponding period in 2000. This change is primarily due to the recording of deferred income taxes in connection with the non-recurring gain recorded in May 2001 arising from the sale of the Company's investment in Powertel, Inc., to Deutsche Telekom AG (see Note 8 of Notes to Condensed Consolidated Financial Statements). Item 3. Quantitative and Qualitative Disclosures About Market Risk All financial instruments held by the Company described below are held for purposes other than trading. Interest rate risk - The table below provides information about the Company's financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates.
September 30, 2001 Expected Maturity Date Millions of dollars There- Fair Liabilities 2001 2002 2003 2004 2005 after Total Value -------------------------------- -------- --------- ---------- ---------- ---------- ---------- ------------ --------- -------------------------------- -------- --------- ---------- ---------- ---------- ---------- ------------ --------- Long-Term Debt: Fixed Rate ($) 9.6 38.1 298.2 186.8 182.0 1,867.4 2,582.1 2,526.7 Average Fixed Interest Rate 8.67 7.21 6.38 7.58 7.43 7.16 7.13 - Variable Rate ($) - 700.0 202.0 - - - 902.0 901.2 Average Variable Interest Rate - 4.27 4.81 - - - 4.39 - Interest Rate Swap: Pay Variable/Receive Fixed ($) - - - - - 300.0 300.0 16.5 Average Pay Interest Rate - - - - - 3.28 3.28 - Average Receive Interest Rate - - - - - 6.88 6.88 -
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. In addition, the Company has an investment in the 11.875 percent senior discount notes (due 2007) of a telecommunications company, the cost basis of which is approximately $63.1 million . As these notes are not publicly traded, determination of their fair value is not practicable. An increase in market interest rates would result in a decrease in fair value of these notes and a corresponding adjustment, net of tax effect, to other comprehensive income. Commodity price risk - The table below provides information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu.
As of September 30, 2001 Expected Maturity in 2001 Expected Maturity in 2002 Expected Maturity in 2003 ------------------------- ------------------------- ------------------------- Weighted Weighted Weighted Average Average Average Settlement Contract Fair Settlement Contract Fair Settlement Contract Fair Natural Gas Derivatives: Price Amount Value Price Amount Value Price Amount Value --------------------------- ----------- ---------- --------- ----------- ---------- ---------- ----------- ---------- --------- (Millions of (Millions of (Millions of dollars) dollars) dollars) Futures Contracts: Long($) 2.50 58.8 32.5 2.80 156.2 103.3 3.30 2.2 1.8 Short($) 2.30 1.1 0.7 2.80 1.9 1.4 - - - --------------------------- ----------- ---------- --------- ----------- ---------- ---------- ----------- -------- ----------- Expected Maturity in 2001 Natural Gas Derivatives: Weighted Average Strike Price Contract Amount ------------------------------- ---------------------------------------- ---------------------------------------- ------------------------------- ---------------------------------------- ---------------------------------------- (Millions of dollars) Options: Purchased call (long)($) 5.827 4.2 ------------------------------- ---------------------------------------- ----------------------------------------
See Note 7 of Notes to Condensed Consolidated Financial Statements for additional information. Equity price risk - Certain investments in telecommunications companies' marketable equity securities are carried at their market value of approximately $671.4 million. A ten percent decline in market value would result in a $67.1 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of other comprehensive income. SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION PART I. FINANCIAL INFORMATION Item 1. Financial Statements SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------------------------- September 30, December 31, Millions of dollars 2001 2000 -------------------------------------------------------------------------------- Assets Utility Plant: Electric $4,550 $4,453 Gas 423 409 Other 187 186 -------------------------------------------------------------------------------- Total 5,160 5,048 Less accumulated depreciation and amortization 1,821 1,720 -------------------------------------------------------------------------------- Total 3,339 3,328 Construction work in progress 355 230 Nuclear fuel, net of accumulated amortization 49 57 -------------------------------------------------------------------------------- Utility Plant, Net 3,743 3,615 -------------------------------------------------------------------------------- Nonutility Property and Investments, Net 23 21 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Current Assets: Cash and temporary investments 37 60 Receivables 239 287 Inventories (at average cost): Fuel 25 21 Materials and supplies 48 46 Emission allowances 15 20 Prepayments 9 5 -------------------------------------------------------------------------------- Total Current Assets 373 439 -------------------------------------------------------------------------------- Deferred Debits: Environmental 26 20 Nuclear plant decommissioning fund 77 72 Pension asset, net 228 196 Other regulatory assets 194 191 Other 131 110 -------------------------------------------------------------------------------- Total Deferred Debits 656 589 -------------------------------------------------------------------------------- Total $4,795 $4,664 ================================================================================ SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------------------------- September 30, December 31, Millions of dollars 2001 2000 -------------------------------------------------------------------------------- Capitalization and Liabilities Stockholders' Investment: Common equity $1,737 $1,657 Preferred stock (Not subject to purchase or sinking funds) 106 106 -------------------------------------------------------------------------------- Total Stockholders' Investment 1,843 1,763 Preferred Stock, net (Subject to purchase or sinking funds) 10 10 Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's Subsidiary Trust, SCE&G Trust I, Holding solely $50 million principal amount of the 7.55% Junior Subordinated Debentures of SCE&G, due 2027 50 50 Long-Term Debt, net 1,414 1,267 -------------------------------------------------------------------------------- Total Capitalization 3,317 3,090 -------------------------------------------------------------------------------- Current Liabilities: Short-term borrowings 75 188 Current portion of long-term debt 28 28 Accounts payable 59 103 Accounts payable - affiliated companies 20 58 Customer deposits 19 17 Taxes accrued 102 51 Interest accrued 29 22 Dividends declared 40 44 Deferred income taxes, net 25 20 Other 6 10 -------------------------------------------------------------------------------- Total Current Liabilities 403 541 -------------------------------------------------------------------------------- Deferred Credits: Deferred income taxes, net 596 584 Deferred investment tax credits 105 109 Reserve for nuclear plant decommissioning 77 72 Postretirement benefits 119 113 Regulatory liabilities 82 65 Other 96 90 -------------------------------------------------------------------------------- Total Deferred Credits 1,075 1,033 -------------------------------------------------------------------------------- Total $4,795 $4,664 ================================================================================ See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS (Unaudited) ---------------------------------------------------------------------------- ------------------------ ----------------------------- Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars 2001 2000 2001 2000 ---------------------------------------------------------------------------- ---------- ------------- --------------- ------------- Operating Revenues: Electric $418 $397 $1,101 $1,011 Gas 43 51 258 203 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Total Operating Revenues 461 448 1,359 1,214 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Operating Expenses: Fuel used in electric generation 69 68 174 180 Purchased power (including affiliated purchases) 70 45 206 112 Gas purchased for resale 33 40 198 140 Other operation and maintenance 78 75 241 229 Depreciation and amortization 41 40 122 119 Other taxes 25 25 75 75 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Total Operating Expenses 316 293 1,016 855 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Operating Income 145 155 343 359 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Other Income: Other Income, including allowance for equity funds used during construction 6 2 20 9 Gain on sale of assets 1 1 2 2 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Total Other Income 7 3 22 11 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 152 158 365 370 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction 26 82 79 26 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 126 132 283 291 Income Taxes 45 49 103 107 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 81 83 180 184 Preferred Dividend Requirement of the Company - Obligated Mandatorily Redeemable Preferred Securities (1) (3) (3) (1) ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Income Before Cumulative Effect of Accounting Change 80 82 177 181 Cumulative Effect of Accounting Change, net of taxes (Note 2) - - - 22 ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Net Income 80 82 177 203 Preferred Stock Cash Dividends Declared (At stated rates) (2) (6) (6) (2) ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Earnings Available for Common Stockholder 78 80 171 197 Retained Earnings at Beginning of Period 665 603 649 550 Common Stock Cash Dividends Declared (38) (41) (115) (105) ---------------------------------------------------------------------------- ---------- -------------- ------------- -------------- Retained Earnings at End of Period $705 $642 $705 $642 ============================================================================ ========== ============== ============= ============== See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) --------------------------------------------------------------------------------------------- Nine Months Ended September 30, Millions of dollars 2001 2000 ------------------------------------------------------------------------------- ------------- Cash Flows From Operating Activities: Net income $177 $203 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - (22) Depreciation and amortization 122 119 Amortization of nuclear fuel 11 15 Gain on sale of assets (2) (2) Allowance for funds used during construction (14) (2) Over (under) collections, fuel adjustment clauses 3 2 Changes in certain assets and liabilities: (Increase) decrease in receivables 48 (6) (Increase) decrease in inventories (1) 4 (Increase) decrease pension asset (32) (42) (Increase) decrease other regulatory assets (4) 12 Increase (decrease) deferred income taxes, net 12 15 Increase (decrease) other regulatory liabilities 19 6 Increase (decrease) postretirement benefits 6 14 Increase (decrease) in accounts payable (82) (11) Increase (decrease) in taxes accrued 51 12 Other, net (3) (3) ------------------------------------------------------------------------------- ------------- Net Cash Provided From Operating Activities 311 314 ------------------------------------------------------------------------------- ------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (263) (176) Nonutility property additions (2) - Proceeds from sale of assets 3 1 Investments (5) (7) ------------------------------------------------------------------------------- ------------- Net Cash Used For Investing Activities (267) (182) ------------------------------------------------------------------------------- ------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 149 148 Capital contribution from Parent 25 - Repayments: First Mortgage Bonds - (100) Other long-term debt (3) (3) Dividend payments: Common stock (119) (87) Preferred stock (6) (6) Short-term borrowings, net (113) (108) ------------------------------------------------------------------------------- ------------- Net Cash Provided From (Used For) Financing Activities (67) (156) ------------------------------------------------------------------------------- ------------- Net Decrease In Cash and Temporary Investments (23) (24) Cash and Temporary Investments, January 1 60 78 ------------------------------------------------------------------------------- ------------- Cash and Temporary Investments, September 30 $37 $54 =============================================================================== ============= Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $7 for 2001 and $3 for 2000) $103 $72 - Income taxes 11 65
See Notes to Condensed Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS September 30, 2001 (Unaudited) The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in South Carolina Electric & Gas Company's (the Company) Annual Report on Form 10-K for the year ended December 31, 2000. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature except as described in Notes 2 and 3, which are necessary for a fair statement of the results for the interim periods reported. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Basis of Accounting The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71. This accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded, as of September 30, 2001, approximately $220 million and $82 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $129 million and $65 million, respectively. The electric and gas regulatory assets of approximately $61 million and $30 million, respectively, (excluding deferred income tax assets) are recoverable through rates. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 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 in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected. B. New Accounting Standards Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. The Company's adoption of SFAS 133, as amended, did not have a material impact on the Company's results of operations, cash flows or financial position. In June 2001 the Financial Accounting Standards Board approved the issuance of three new accounting standards. SFAS 141, "Business Combinations," requires that all business combinations be accounted for using the purchase method of accounting. SFAS 141 applies to all business combinations initiated after June 30, 2001, and is not expected to have any impact on the Company's results of operations, cash flows or financial position. SFAS 142, "Goodwill and Other Intangible Assets," requires that goodwill not be amortized but instead be tested for impairment at least annually at the reporting unit level. A reporting unit is the same level as, or one level below, an operating segment. The Company will adopt SFAS 142 effective January 1, 2002. The impact SFAS 142 may have on the Company's results of operations, cash flows or financial position has not been determined. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined. C. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2001. 2. Cumulative Effect of Accounting Change Effective January 1, 2000 the Company changed its method of accounting for operating revenues from cycle billing to full accrual. The cumulative effect of this change was $22 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. 3. RATE AND OTHER REGULATORY MATTERS A. On April 24, 2001 the Public Service Commission of South Carolina (PSC) approved the Company's request to increase the fuel component of rates charged to electric customers from 1.330 cents per kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2001 through April 2002. The increase also provides recovery over a two-year period of under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of the Company's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2001. B. On July 20, 2000 the PSC approved the Company's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. As part of its regularly scheduled annual review of gas costs, the PSC issued an order on November 9, 2000 which further increased the cost of gas component to 78.151 cents per therm, effective with the first billing cycle in November 2000. On December 21, 2000 the PSC issued an order approving the Company's request for another out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. On March 9, 2001 the PSC issued an order granting the Company's request to reduce the cost of gas component to 79.340 cents per therm, effective with the first billing cycle in March 2001. On October 23, 2001, as part of the annual review of gas costs, the PSC approved the Company's request to further reduce the cost of gas component to 59.646 cents per therm effective with the first billing cycle in November 2001. C. On July 5, 2000 the PSC approved the Company's request to implement lower depreciation rates for its gas operations. The new rates were effective retroactively to January 1, 2000 and resulted in a reduction in annual depreciation expense of approximately $2.9 million. The retroactive effect was recorded in the second quarter of 2000. D. On September 14, 1999 the PSC approved an accelerated capital recovery plan for the Company's Cope Generating Station. The plan was implemented beginning January 1, 2000 for a three-year period. The PSC approved an accelerated capital recovery methodology wherein the Company may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates. The amount of the accelerated depreciation will be determined by the Company based on the level of revenues and operating expenses, not to exceed $36 million annually without the approval of the PSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. As of September 30, 2001 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. E. On January 9, 1996 the PSC issued an order granting the Company an increase in retail electric rates which was fully implemented by January 1997. The PSC authorized a return on common equity of 12.0 percent. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally the PSC approved accelerated amortization of a significant portion of the Company's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, which enabled the Company to recover the balances as of the end of the year 2000. F. In 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants (MGPs). The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been deferred. In October 2001, as a result of the annual review, the PSC approved the Company's request to increase the billing surcharge from $1.1 cents per therm to $3.0 cents per therm, which is intended to provide for the recovery of the balance remaining at September 30, 2001 of $25.9 million prior to the end of the year 2005. 4. LONG-TERM DEBT On January 24, 2001 the Company issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. 5. RETAINED EARNINGS The Company's Restated Articles of Incorporation and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At September 30, 2001 approximately $36 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock. 6. CONTINGENCIES With respect to commitments at September 30, 2001, reference is made to Note 12 of Notes to Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2000. Contingencies at September 30, 2001 include the following: A. Lake Murray Dam Reinforcement On October 15, 1999 the Federal Energy Regulatory Commission (FERC) notified the Company of its agreement with the Company's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. Construction for the project, which began in the third quarter of 2001, could cost up to $300 million with completion dates ranging from 2004 to 2006. Although any costs incurred by the Company are expected to be recoverable through electric rates, the Company also is exploring alternative sources of funding. B. Nuclear Insurance The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $9.5 billion. Each reactor licensee is currently liable for up to $88.1 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. The Company's maximum assessment, based on its two-thirds ownership of the V. C. Summer Nuclear Station (Summer Station), would be approximately $58.7 million per incident, but not more than $6.7 million per year. The Company currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit assessments under certain conditions to cover insurer's losses. Based on the current annual premium, the Company's portion of the retrospective premium assessment would not exceed $8.1 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 the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it could have a material adverse impact on the Company's results of operations, cash flows and financial position. C. Environmental The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up 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 cleanup relate primarily to regulated operations. Such amounts are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.9 million at September 30, 2001. The deferral includes the estimated costs associated with the following matters. o In September 1992 the Environmental Protection Agency (EPA) notified the Company, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park area site in Charleston, South Carolina. This site encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of the Company's decommissioned MGPs, properties owned by the National Park Service and the City of Charleston and private properties. The site has not been placed on the National Priorities List, but may be added in the future. The Potentially Responsible Parties (PRPs) negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993, and the EPA approved a Remedial Investigation Report in February 1997 and a Feasibility Study Report in June 1998. In July 1998 the EPA approved the Company's Removal Action Work Plan for soil excavation. In September 1998 a Record of Decision was issued which sets forth the EPA's view of the extent of each PRP's responsibility for site contamination and the level to which the site must be remediated. In January 1999 the EPA issued a Unilateral Administrative Order for Remedial Design and Remedial Action directing the Company to design and carry out a plan of remediation for the Calhoun Park site. The Company submitted a Comprehensive Remedial Design Work Plan (RDWP) in December 1999 and proceeded with implementation pending agency approval. The RDWP was approved by the EPA in July 2000, and its implementation continues. In September 2000, the Company was notified by the South Carolina Department of Health and Environmental Control (DHEC) that benzene contamination was detected in the intermediate aquifer on surrounding properties to the Calhoun Park Area site. The EPA required that the Company conduct a focused Remedial Investigation/Feasibility Study on the intermediate aquifer, which was completed in June 2001. The EPA expects to issue a second Record of Decision dealing with the intermediate aquifer in the fourth quarter of 2001.. As of September 30, 2001, the Company has spent approximately $14.8 million to remediate the Calhoun Park area site. Total remediation costs are estimated to be $21.9 million. o The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. For the site located in Sumter, effective September 15, 1998, the Company entered into a Remedial Action Plan Contract with DHEC pursuant to which it agreed to undertake a full site investigation and remediation under the oversight of DHEC. Site investigation, characterization and remediation are proceeding according to schedule. Excavation at the Sumter MGP site was completed in May 2001 as part of an Interim Removal Action. Further work may be required at the discretion of DHEC. Upon successful implementation of a site remedy, DHEC will give the Company a Certificate of Completion and a covenant not to sue. For the site located in Florence the Company entered into a similar Remedial Action Plan Contract with DHEC in September 2000. The Company is continuing to investigate the remaining site in Columbia, and is monitoring the nature and extent of residual contamination. 7. 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 reportable segments. Therefore, net income is not allocated to these segments. Affiliate revenue is derived from transactions between reportable segments as well as transactions between separate legal entities that are combined into the same reportable segment. Accumulated depreciation is not assignable to the Company's segments. Disclosure of Reportable Segments (Millions of Dollars) ------------------------------------ ------------------------------------------- Three months ended Electric Gas Adjustments/ Consolidated September 30, 2001 Operations Distribution Eliminations Total ------------------------------------ ------------------------------------------- External Revenue 418 43 - 461 Intersegment Revenue 66 - (66) - Operating Income (Loss) 151 (5) (1) 145 Segment Assets 4,878 427 (510) 4,795 ------------------------------------ ------------ ------------------------------ Nine months ended Electric Gas Adjustments/ Consolidated September 30, 2001 Operations Distribution Eliminations Total ------------------------------------ ------------ ------------------------------ External Revenue 1,101 258 - 1,359 Intersegment Revenue 165 - (165) - Operating Income (Loss) 334 12 (3) 343 Segment Assets 4,878 427 (510) 4,795 ------------------------ ------------ ----------------------------------------- Three months ended Electric Gas Adjustments/ Consolidated September 30, 2000 Operations Distribution Eliminations Total ------------------------------------ ------------ ------------------------------ External Revenue 397 51 - 448 Intersegment Revenue 63 - (63) - Operating Income (Loss) 160 (4) (1) 155 Segment Assets 4,576 411 (471) 4,516 ------------------------ ------------ ------------ ----------------------------- Nine months ended Electric Gas Adjustments/ Consolidated September 30, 2000 Operations Distribution Eliminations Total ------------------------ ------------ ------------ ----------------------------- External Revenue 1,011 203 - 1,214 Intersegment Revenue 169 - (169) - Operating Income (Loss) 345 17 (3) 359 Segment Assets 4,576 411 (471) 4,516 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ----------------------------------------------------------------------- SOUTH CAROLINA ELECTRIC & GAS COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in South Carolina Electric & Gas Company's (SCE&G) Annual Report on Form 10-K for the year ended December 31, 2000. Statements included in this discussion and analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy especially in SCE&G's service territory, (4) the impact of competition from other energy suppliers, (5) growth opportunities, (6) the results of financing efforts, (7) changes in SCE&G's accounting policies, (8) weather conditions, especially in areas served by SCE&G, (9) inflation, (10) changes in environmental regulations and (11) the other risks and uncertainties described from time to time in SCE&G's periodic reports filed with the Securities and Exchange Commission. SCE&G disclaims any obligation to update any forward-looking statements. LIQUIDITY AND CAPITAL RESOURCES On October 15, 1999 the Federal Energy Regulatory Commission (FERC) notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. Construction for the project, which began in the third quarter of 2001, could cost up to $300 million with completion dates ranging from 2004 to 2006. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. On February 9, 2000 FERC issued FERC Order 2000. The Order required utilities which operate electric transmission systems to submit plans for the formation of regional transmission organizations (RTOs). In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth) as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In July 2001 FERC expressed its desire that utilities throughout the U. S. combine their transmission systems to create four large independent regional operators, one each in the Northeast, Southeast, Midwest and West. Accordingly, FERC ordered mediation talks to take place between the utilities forming GridSouth and certain groups that had proposed other RTOs. These talks were mediated by an administrative law judge, who issued her nonbinding mediation report in September 2001. The report made recommendations related to the formation of a Southeast regional RTO. FERC has not acted on the mediation report, and the timing or impact of future FERC orders related to RTOs cannot be predicted. In March 2001 V. C. Summer Nuclear Station returned to service. It had been taken out of service on October 7, 2000 for a planned maintenance and refueling outage. During initial inspection activities, plant personnel discovered a small leak coming from a hole in a weld in a primary coolant system pipe. Repairs were completed and the integrity of the new welds was verified through extensive testing. The PSC has approved recovery of the cost of replacement power through SCE&G's electric fuel adjustment clause (see Note 3A of Notes to Condensed Consolidated Financial Statements). The Nuclear Regulatory Commission was closely involved throughout this process and approved SCE&G's actions to repair the crack, as well as the restart schedule. SCE&G will continue to monitor primary coolant system pipes during the next outage, scheduled for the spring of 2002. In April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station returned to service. It had been taken out of service in January 2001 due to an electrical ground in the generator. The PSC has approved recovery of the cost of replacement power through SCE&G's electric fuel adjustment clause (see Note 3A of Notes to Condensed Consolidated Financial Statements). In October 2001 SCE&G filed with the PSC its siting plans to construct an 875 megawatt generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. Construction of the $450 million facility is expected to begin in April 2002, with commercial operation in the summer of 2004. In connection with the facility, SCE&G has signed a 250 megawatt electric supply contract with North Carolina Electric Membership Corporation for a term of at least five years beginning January 1, 2004. The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the nine months ended September 30, 2001 and 2000: ---------------------------------------------------------------------------- Nine Months Ended September 30, Millions of dollars 2001 2000 -------------------------------------------------------------- ------------- Net cash provided from operating activities $311 $314 Net cash used for financing activities (67) (156) at the beginning of the period 60 78 -------------------------------------------------------------------------------- Net cash available for utility property additions and construction expenditures $304 $236 ================================================================================ Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $263 $176 Funds used for nonutility property additions $2 $- ================================================================= ============= On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. The proceeds were used to reduce short-term debt and for general corporate purposes. SCE&G anticipates that the remainder of its 2001 cash requirements will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months ended September 30, 2001 was 3.91. Environmental Matters For information on environmental matters see Note 6C of Notes To Condensed Consolidated Financial Statements. RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2001 AS COMPARED TO THE CORRESPONDING PERIODS IN 2000 Earnings and Dividends Net income components for the three and nine months ended September 30, 2001 and 2000 were as follows: ---------------------------- ------------------------------------------------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 2001 2000 ---------------------------- ----------- ------------------------ ------------ Net income derived from: Operations $79.7 $82.0 $176.2 $180.5 Cumulative effect of change in accounting - - - 22.3 --------------------------------------- ------------- ---------- ------------- Total net income $79.7 $82.0 $176.2 $202.8 ======================================= ============= ========== ============= Net income from operations for the three months ended September 30, 2001 decreased primarily due to milder weather, an increase in other operation and maintenance expense and an economic slowdown, which were partially offset by customer growth. Net income from operations for the nine months ended September 30, 2001 decreased primarily due to milder weather, increases in interest expense and other operation and maintenance expense and an economic slowdown, which were partially offset by customer growth. For the last several years, the market value of the Company's retirement plan assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income for the three and nine months ended September 30, 2001 was $11.1 million and $29.5 million, compared to $12.6 million and $30.7 million, respectively, for the corresponding periods in 2000. As a result of pension income, employee benefit expenses were reduced approximately $5.8 million and $15.4 million for the three and nine months ended September 30, 2001. For the corresponding periods in 2000, employee benefit expenses were reduced approximately $6.9 million and $16.4 million. Additionally, other income increased $3.7 million and $9.7 million for the three and nine months ended September 30, 2001. For the corresponding periods in 2000, other income increased $3.9 million and $9.9 million, respectively. Earnings from the cumulative effect of change in accounting resulted from recording of unbilled revenue (See Note 2 of Notes to Condensed Consolidated Financial Statements). Allowance for funds used during construction (AFC) is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Both the equity and the debt portions of AFC are noncash items of nonoperating income which have the effect of increasing reported net income. AFC represented approximately five percent of income before income taxes for the three and nine months ended September 30, 2001, respectively. For the three and nine months ended September 30, 2000, AFC represented approximately one percent of income before income taxes. SCE&G's Board of Directors declared the following quarterly dividends on common stock held by SCANA, during 2001: ---------------------- ------------------ --------------------- ---------------- Declaration Dividend Quarter Payment Date Amount Ended Date ---------------------- ------------------ --------------------- ---------------- February 22, 2001 $35.0 million March 31, 2001 April 1, 2001 ---------------------- May 3, 2001 $41.75 million June 30, 2001 July 1, 2001 ---------------------- August 2, 2001 $38.5 million September 30, 2001 October 1, 2001 ---------------------- November 1, 2001 $40.0 million December 31, 2001 January 1, 2002 ---------------------- ------------------ --------------------- ---------------- Electric Operations Electric Operations is comprised of the electric portion of SCE&G and South Carolina Fuel Company. Changes in the electric operations sales margins, excluding the cumulative effect of accounting change, for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
--------------------------------- ------------------------------------------ ---------------------------------------------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change --------------------------------- --------- --------- ---------------------- ----------- ----------- ---------------------- Electric operating revenue $417.6 $396.7 $20.9 5.3% $1,101.0 $1,010.8 $90.2 8.9% Less: Fuel used in generation 69.1 67.6 1.5 2.2% 173.8 179.8 (6.0) (3.3)% Purchased power 69.6 45.2 24.4 54.0% 205.5 111.9 93.6 83.6% --------------------------------- ---------- ----------- ----------- ----------- --------- --------- Margin $278.9 $283.9 $(5.0) (1.8)% $721.7 $719.1 $2.6 0.4% ================================= ========= ========= ========== =========== =========== =========== =========== ========== *Greater than 100% -
Changes in electric operations sales margins for the three months ended September 30, 2001 reflect milder weather and an economic slowdown. Purchased power increased primarily due to power purchased for resale. As a result, operating revenue also increased, but was partially offset by the effects of milder weather and the economic slowdown. Changes in electric operations sales margin for the nine months ended September 30, 2001 reflect steady customer growth partially offset by the effects of milder weather and the economic slowdown. Increases in purchased power costs for the nine months, as compared to the corresponding period in 2000, were primarily attributable to plant outages discussed at Liquidity and Capital Resources, which delayed scheduled maintenance outages at other plants until April and May 2001, and to power purchased for resale in the third quarter. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Changes in the gas distribution sales margins, excluding the cumulative effect of accounting change, for the three and nine months ended September 30, 2001, when compared to the corresponding periods in 2000, were as follows:
------------------------------------ ----------------------------------------- --------------------------------------------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change ------------------------------------ --------- --------- --------------------- ----------- ---------- ---------------------- Gas operating revenue $43.0 $51.4 $(8.4) (16.3)% $257.9 $202.9 $55.0 27.1% Less: Gas purchased for resale 32.6 40.2 (7.6) (18.9)% 198.0 140.4 57.6 41.0% ------------------------------------ ---------- ----------- ---------- ----------- --------- --------- Margin $10.4 $11.2 $(0.8) (7.1)% $59.9 $62.5 $(2.6) (4.2)% ==================================== ========= ========= ========== ========== =========== ========== =========== ==========
Gas distribution sales margins for the three and nine months ended September 30, 2001 reflect milder weather and an economic slowdown. Revenues and purchases for the nine months ended September 30, 2001 were impacted by large increases in natural gas prices in late 2000 and early 2001. The increased cost of gas was passed on to customers as discussed in Note 3B in Notes To Condensed Consolidated Financial Statements. Other Operating Expenses Changes in other operating expenses for the three and nine months ended September 30, 2001 when compared to the corresponding periods in 2000, were as follows:
-------------------------------------- ---------------------------------------- -------------------------------------------- Three Months Ended Nine Months Ended Millions of dollars 2001 2000 Change 2001 2000 Change -------------------------------------- --------- -------- --------------------- ---------- ---------- ---------------------- Other operation and maintenance $78.4 $75.2 $3.2 4.3% $240.9 $229.3 $11.6 5.1% Depreciation and amortization 40.9 39.6 1.3 3.3% 122.5 118.8 3.7 3.1% Other taxes 24.8 25.5 (0.7) (2.7)% 75.2 75.1 0.1 0.1% -------------------------------------- --------- ---------- ---------- ------------- --------- -------- Total $144.1 $140.3 $3.8 2.7% $438.6 $423.2 $15.4 3.6% ====================================== ========= ======== ========= =========== ========== ========== ============= ========
Other operation expenses for the three and nine months ended September 30, 2001 increased primarily as a result of increases in employee benefit costs. The increase in depreciation and amortization expenses for the three and nine months ended September 30, 2001 resulted from normal property additions. Item 3. Quantitative and Qualitative Disclosures About Market Risk All financial instruments held by SCE&G and described below are held for purposes other than trading. Interest rate risk - The table below provides information about SCE&G's financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates.
September 30, 2001 Millions of dollars Expected Maturity Date There- Fair Liabilities 2001 2002 2003 2004 2005 after Total Value --------------------------------- -------- ------- --------- ---------- ----------- ----------- ---------- --------------------------------- -------- ------- --------- ---------- ----------- ----------- ---------- Long-Term Debt: Fixed Rate ($) 1.3 27.6 129.5 123.9 173.9 1,082.3 1,538.5 1,478.7 Average Interest Rate 6.50 6.72 6.37 7.52 7.40 7.43 7.33 -
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED FINANCIAL SECTION PART I. FINANCIAL INFORMATION Item 1. Financial Statements. -------------------- PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------------------------- September 30, December 31, Millions of dollars 2001 2000 -------------------------------------------------------------------------------- Assets Gas Utility Plant $822 $787 Less accumulated depreciation 282 263 Acquisition adjustment, net of accumulated amortization 443 452 -------------------------------------------------------------------------------- Gas Utility Plant, Net 983 976 -------------------------------------------------------------------------------- Nonutility Property and Investments, Net 28 34 -------------------------------------------------------------------------------- Current Assets: Cash and temporary investments 21 8 Restricted cash and temporary investments 1 5 Receivables (net of allowance for uncollectible accounts of $1 for 2001 and $2 for 2000) 41 148 Inventories (at average cost): Stored gas 47 32 Materials and supplies 8 7 Other 4 2 -------------------------------------------------------------------------------- Total Current Assets 122 202 -------------------------------------------------------------------------------- Deferred Charges and Other Assets: Due from affiliate-pension asset 10 10 Regulatory assets 11 21 Other 8 10 -------------------------------------------------------------------------------- Total Deferred Charges and Other Assets 29 41 -------------------------------------------------------------------------------- Total 1,162 $1,253 ================================================================================ ================================================================================ Capitalization and Liabilities Capitalization: Common equity $706 $712 Long-term debt, net 295 145 -------------------------------------------------------------------------------- Total Capitalization 1,001 857 -------------------------------------------------------------------------------- Current Liabilities: Short-term borrowings - 125 Current portion of long-term debt 4 4 Accounts payable 17 84 Taxes accrued - 3 Customer prepayments and deposits 11 8 Advances from parent - 44 Dividends declared and interest accrued 7 5 Other 3 6 -------------------------------------------------------------------------------- Total Current Liabilities 42 279 -------------------------------------------------------------------------------- Deferred Credits and Other Liabilities: Deferred income taxes, net 84 82 Deferred investment tax credits 2 3 Due to affiliate-postretirement benefits 11 10 Regulatory liabilities 5 - Other 17 22 ----------------------------------------------------------- ------- Total Deferred Credits and Other Liabilities 119 117 -------------------------------------------------------------------------------- Total $1,162 $1,253 ================================================================================ See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND RETAINED EARNINGS (DEFICIT) (Unaudited) ---------------------------------------------------------------------- --------------------------- ------------------------------ Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars 2001 2000 2001 2000 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Operating Revenues $47 $76 $343 $326 Cost of Gas 25 54 228 210 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Gross Margin 22 22 115 116 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Operating Expenses: Operation and maintenance 19 17 51 52 Depreciation and amortization 10 10 32 31 Other taxes 2 2 5 5 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Total Operating Expenses 31 29 88 88 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Operating Income (Loss) (9) (7) 27 28 Other Income, net 1 2 5 5 Interest Charges 6 5 16 15 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change (14) (10) 16 18 Income Taxes (Benefit) (4) (2) 10 12 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Income (Loss) Before Cumulative Effect of Accounting Change (10) (8) 6 6 Cumulative Effect of Accounting Change, net of taxes (Note 2) - - - 7 ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Net Income (Loss) (10) (8) 6 13 Retained Earnings at Beginning of Period 13 10 9 73 Acquisition of Company - - - (73) Common Stock Cash Dividends Declared (3) (5) (15) (16) ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- ---------------------------------------------------------------------- ------------ -------------- --------------- -------------- Retained Earnings (Deficit) at End of Period $- $(3) $- $(3) ====================================================================== ============ ============== =============== ============== See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) ---------------------------------------------------------------------------------------------- ---------------------------- Nine Months Ended September 30, Millions of dollars 2001 2000 ---------------------------------------------------------------------------------------------- --------------- ------------ Cash Flows From Operating Activities: Net income $6 $13 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - (7) Depreciation and amortization 37 35 Excess distributions (undistributed earnings) of investee 3 (2) Over (under) collection, fuel adjustment clause 14 2 Changes in certain assets and liabilities: (Increase) decrease in receivables, net 96 38 (Increase) decrease in inventories (17) (11) (Increase) decrease in regulatory assets 1 (5) Increase (decrease) in accounts payable and advances (101) (6) Increase (decrease) in deferred income taxes, net 2 2 Increase (decrease) in accrued taxes (2) (2) Other, net 2 2 ---------------------------------------------------------------------------------------------- --------------- ------------ Net Cash Provided From Operating Activities 41 59 ---------------------------------------------------------------------------------------------- --------------- ------------ Cash Flows From Investing Activities: Construction expenditures (41) (25) Investments - (1) Nonutility and other 1 - ---------------------------------------------------------------------------------------------- --------------- ------------ Net Cash Used For Investing Activities (40) (26) ---------------------------------------------------------------------------------------------- --------------- ------------ Cash Flows From Financing Activities: Issuance of medium-term notes 148 - Repayment of short-term borrowings, net (125) (13) Retirement of long-term debt and common stock - (1) Capital contribution from parent 4 - Cash dividends (15) (16) ---------------------------------------------------------------------------------------------- --------------- ------------ Net Cash Provided From (Used For) Financing Activities 12 (30) ---------------------------------------------------------------------------------------------- --------------- ------------ Net Increase In Cash and Temporary Investments 13 3 Cash and Temporary Investments, January 1 8 9 ---------------------------------------------------------------------------------------------- --------------- ------------ Cash and Temporary Investments, September 30 $21 $12 ============================================================================================== =============== ============ Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $0.8 for 2001 and $0.7 for 2000) $12 $15 - Income taxes 15 14
In connection with the acquisition of Public Service Company of North Carolina, Inc. by SCANA Corporation, $21 million in common stock was cancelled. The application of push-down accounting for the acquisition resulted in a $466 million acquisition adjustment. Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., an affiliate, for $4.4 million, which approximated net book value. Assets transferred included approximately $4.0 million in cash. See Notes to Condensed Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS September 30, 2001 (Unaudited) The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in Public Service Company of North Carolina, Incorporated's (the Company) Annual Report on Form 10-K for the year ended December 31, 2000. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income (Loss) are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature except as described in Notes 2, 3, 4 and 5, which are necessary for a fair statement of the results for the interim periods reported. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Basis of Accounting The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71. This accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of September 30, 2001, approximately $11 million and $5 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax liabilities of approximately $0.2 million. The regulatory assets are recoverable through rates. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 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 in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected. B. New Accounting Standards Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. The Company's adoption of SFAS 133, as amended, did not have a material impact on the Company's results of operations, cash flows or financial position. In June 2001 the Financial Accounting Standards Board approved the issuance of three new accounting standards. SFAS 141, "Business Combinations," requires that all business combinations be accounted for using the purchase method of accounting. SFAS 141 applies to all business combinations initiated after June 30, 2001, and is not expected to have any impact on the Company's results of operations, cash flows or financial position. SFAS 142, "Goodwill and Other Intangible Assets," requires that goodwill not be amortized but instead be tested for impairment at least annually at the reporting unit level. A reporting unit is the same level as, or one level below, an operating segment. The Company will adopt SFAS 142 effective January 1, 2002. The impact SFAS 142 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset. The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined. C. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2001. 2. CUMULATIVE EFFECT OF ACCOUNTING CHANGE Effective January 1, 2000 the Company changed its method of accounting for operating revenues from cycle billing to full accrual. The cumulative effect of this change was $6.6 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. Also, effective January 1, 2000 the gas costs associated with unbilled revenues are no longer deferred. 3. ACQUISITION BY SCANA CORPORATION On February 10, 2000 the acquisition of the Company by SCANA Corporation (SCANA) was consummated in a business combination accounted for as a purchase. As a result the Company became a wholly owned subsidiary of SCANA. Pursuant to the Agreement and Plan of Merger, the Company shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. The Company has recorded a utility plant acquisition adjustment of approximately $466 million, which reflects the excess of SCANA's purchase price of approximately $700 million over the fair value of the Company's net assets at January 1, 2000. The adjustment is being amortized over 35 years on a straight-line basis. Common equity at September 30, 2001 and December 31, 2000 reflects the effect of this acquisition adjustment. Severance benefits of approximately $4.4 million have been paid to eight key executives. In addition, approximately $3.1 million was paid to former directors of the Company in connection with deferred compensation and retirement plans, and approximately $8.1 million was paid to participants in the Company's nonqualified stock option plans. 4. SALE OF PSNC PRODUCTION CORPORATION AND SCANA PUBLIC SERVICE LLC PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, for $4.4 million, which approximated net book value, effective January 1, 2001. 5. RATE AND OTHER REGULATORY MATTERS PSNC's rates are established using a benchmark cost of gas approved by the North Carolina Utilities Commission (NCUC) which may be modified periodically to reflect changes in the commodity price of natural gas purchased by PSNC. PSNC may file revised tariffs with the NCUC coincident with these changes or it may track the changes in its deferred accounts for subsequent rate consideration. The rules of the NCUC allow recovery of all prudently incurred gas costs. The NCUC reviews PSNC's gas purchasing practices annually. PSNC's benchmark cost of gas in effect during the nine months ended September 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date -------------- -------------- -------------- -------------- $.690 January 2001 $.300 January 2000 $.750 February-March 2001 $.265 February-May 2000 $.650 April-August 2001 $.350 June 2000 $.500 September 2001 $.450 July-September 2000 On April 6, 2000 the NCUC issued an order permanently approving the Company's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. The NCUC previously allowed the Company use of this mechanism on a trial basis. This mechanism allows the Company to collect from its customers amounts approximating the amounts paid for natural gas. A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from the Company's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On December 30, 1999 the Company filed an application with the NCUC to extend natural gas service to Madison, Jackson and Swain Counties, North Carolina. Pursuant to state statutes, the NCUC required the Company to forfeit its exclusive franchises to serve six counties in western North Carolina effective January 31, 2000 because these counties were not receiving any natural gas service. Madison, Jackson and Swain Counties were included in the forfeiture order. On June 29, 2000 the NCUC approved the Company's requests for reinstatement of its exclusive franchises for Madison, Jackson and Swain Counties and disbursement of up to $28.4 million from the Company's expansion fund for this project. The Company estimates that the cost of this project will be approximately $31.4 million. The Madison County portion of the project was completed at a cost of approximately $5.7 million, and customers began receiving service in July 2001. On December 7, 1999 the NCUC issued an order approving the acquisition of the Company by SCANA. As specified in the NCUC order, the Company reduced its rates by approximately $1 million in each of August 2000 and August 2001, and has agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events. 6. LONG-TERM DEBT On February 16, 2001 the Company issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. The proceeds were used to reduce short-term debt and for general corporate purposes. 7. CONTINGENCIES The Company owns, or has owned, all or portions of seven sites in North Carolina on which manufactured gas plants (MGPs) were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. The North Carolina Department of Environment and Natural Resources (DENR) has recommended that no further action be taken with respect to one site. Excavation at the Raleigh MGP site was completed in March 2001 as part of an Interim Removal Action. Further work at this site may be required at the discretion of DENR. Work at the Durham MGP site began in May 2001 under a DENR-approved Phase II Workplan. An environmental due diligence review of the Company conducted in February 1999 estimated that the cost to remediate the sites would range between $11.3 million and $21.9 million. During the second quarter of 2000, the review was finalized and the estimated liability was recorded. The Company is unable to determine the rate at which costs may be incurred over this time period. The estimated cost range has not been discounted to present value. The Company's associated actual 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 (PRPs). A May 1993 order by the NCUC authorized deferral accounting for all costs associated with the investigation and remediation of MGP sites. As of September 30, 2001 the Company has recorded a liability and associated regulatory asset of $9.1 million, which reflects the minimum amount of the range, net of shared cost recovery expected from other PRPs and expenditures for work completed. Amounts incurred to date are approximately $1.1 million. Management intends to request recovery of additional MGP clean-up costs not recovered from other PRPs in future rate case filings, and believes that all costs incurred will be recoverable in gas rates. 8. SEGMENT OF BUSINESS INFORMATION For the three and nine months ended September 30, 2001 Gas Distribution is the Company's only reportable segment. Gas Distribution uses operating income to measure profitability. Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service Company LLC (SCANA Public Service) were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA (see Note 4). In 2000 SCANA Public Service was an Energy Marketing segment of the Company and used net income to measure profitability.
Disclosure of Reportable Segments (Millions of Dollars) -------------------------------- ----------------- ----------------- ------------------ ------------------ Three months ended Gas Energy Adjustments/ Consolidated September 30, 2001 Distribution Marketing Eliminations Total -------------------------------- ----------------- ----------------- ------------------ ------------------ External Revenue 47 n/a - 47 Intersegment Revenue - n/a - - Operating Income (Loss) (9) n/a - (9) Segment Assets 1,148 n/a 14 1,162 ----------------------------- --------------------- ----------------- ------------------- ---------------- Three months ended Gas Energy Adjustments/ Consolidated September 30, 2000 Distribution Marketing Eliminations Total ----------------------------- --------------------- ----------------- ------------------- ---------------- External Revenue 46 30 - 76 Intersegment Revenue - - - - Operating Income (Loss) (7) n/a - (7) Net Income n/a - (8) (8) Segment Assets 1,138 17 1 1,156 ------------------------------ --------------------- ----------------- ------------------- ---------------- Nine months ended Gas Energy Adjustments/ Consolidated September 30, 2001 Distribution Marketing Eliminations Total ------------------------------ --------------------- ----------------- ------------------- ---------------- External Revenue 343 n/a - 343 Intersegment Revenue - n/a - - Operating Income 27 n/a - 27 Segment Assets 1,148 n/a 14 1,162 ------------------------------ --------------------- ----------------- -------------------- --------------- Nine months ended Gas Energy Adjustments/ Consolidated September 30, 2000 Distribution Marketing Eliminations Total ------------------------------ --------------------- ----------------- -------------------- --------------- External Revenue 267 85 (26) 326 Intersegment Revenue - 2 (2) - Operating Income 26 n/a 2 28 Net Income n/a 1 121 13 Segment Assets 1,138 17 1 1,156 1 Includes cumulative effect of accounting change (See Note 2).
Item 2. Management's Narrative Analysis of Results of Operations. --------------------------------------------------------- PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS The following discussion should be read in conjunction with Management's Narrative Analysis of Results of Operations appearing in Public Service Company of North Carolina, Incorporated's (PSNC) Annual Report on Form 10-K for the year ended December 31, 2000. Statements included in this narrative analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, forward-looking statements for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that 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) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy, especially in PSNC's service territory, (4) the impact of competition from other energy suppliers, (5) growth opportunities, (6) the results of financing efforts, (7) changes in PSNC's accounting policies, (8) weather conditions, especially in areas served by PSNC, (9) inflation, (10) changes in environmental regulations and (11) the other risks and uncertainties described from time to time in PSNC's periodic reports filed with the Securities and Exchange Commission. PSNC disclaims any obligation to update any forward-looking statements. Capital Expansion Program PSNC's capital expansion program, through the construction of lines, services, systems and facilities, and the purchase of equipment, is designed to help PSNC meet the growing demand for natural gas in its franchised service areas. PSNC's 2001 construction budget is approximately $58.0 million, compared to actual construction expenditures for 2000 of $39.1 million. The construction program is reviewed regularly by management and is dependent upon PSNC's continuing ability to generate adequate funds internally and to sell new issues of debt on acceptable terms. Construction expenditures during the nine months ended September 30, 2001 were $41.1 million compared to $24.6 million for the same period in 2000. PSNC's ratio of earnings to fixed charges for the 12 months ended September 30, 2001 was 3.0. Earnings and Dividends Net income components for the nine months ended September 30, 2001 and 2000 were as follows: -------------------------------------------------------------------------------- Nine Months Ended September 30, Millions of dollars 2001 2000 ------------------------------------------------------------------- ------------ Net income derived from: Operations $5.7 $6.3 Cumulative effect of change in accounting - 6.6 ------------------------------------------------------------------- ------------ Total net income $5.7 $12.9 =================================================================== ============ Net income from operations for the nine months ended September 30, 2001 decreased primarily due to the sale of PSNC Production Corporation (see Note 4 of Notes to Condensed Consolidated Financial Statements), which was partially offset by customer growth. In 2000 net income reflects a change in accounting to record unbilled revenue (see Note 2). PSNC's Board of Directors declared the following dividends on common stock held by SCANA during 2001: -------------------- ------------------- -------------------- ------------------ Declaration Date Dividend Amount Quarter Ended Payment Date -------------------- ------------------- -------------------- ------------------ February 22, 2001 $6.0 million March 31, 2001 April 1, 2001 May 3, 2001 $5.8 million June 30, 2001 July 1, 2001 August 2, 2001 $3.0 million September 30, 2001 October 1, 2001 -------------------- ------------------- -------------------- ------------------ Gas Distribution Changes in gas distribution sales margins for the nine months ended September 30, 2001, when compared to the corresponding period in 2000, were as follows: ------------------------------------------------------------------------------- Nine Months Ended September 30, Millions of dollars 2001 2000 Change -------------------------------------- ------------- -------------------------- Gas operating revenue $342.9 $326.3 $16.6 5.1% Less: Cost of gas 227.8 210.5 17.3 8.2% -------------------------------------- ------------- ------------- Gross margin $115.1 $115.8 $(0.7) (0.6)% ====================================== ============= ============= ============ Gas distribution sales margin for the nine months ended September 30, 2001 decreased as a result of lower gas usage by residential customers and the sale of PSNC Production Corporation (see Note 4 of Notes to the Condensed Consolidated Financial Statements), which more than offset increased customer growth. Revenues and cost of gas were impacted by large increases in natural gas prices in late 2000 and early 2001. The increased cost of gas was passed on to customers. Operating Expenses Operating and maintenance expenses for the nine months ended September 30, 2001 decreased $0.8 million when compared to the corresponding period in 2000 primarily due to reduced costs related to employee benefits and advertising and the sale of PSNC Production. The increase was partially offset by an increased provision for bad debt. PART II. OTHER INFORMATION Item 1. Legal Proceedings SCANA Corporation: For information regarding legal proceedings see Note 4 of Notes To Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2000, and Note 4 and Note 9 of Notes To Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q. South Carolina Electric & Gas Company: For information regarding legal proceedings see Note 3," of Notes To Consolidated Financial Statements appearing in South Carolina Electric & Gas Company's Annual Report on Form 10-K for the year ended December 31, 2000, and Note 3 and Note 6 " of Notes To Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q. Public Service Company of North Carolina, Incorporated: For information regarding legal proceedings see Note 5 of Notes To Consolidated Financial Statements appearing in Public Service Company of North Carolina, Incorporated's Annual Report on Form 10-K for the year ended December 31, 2000, and Note 5 and Note 7 of Notes To Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q. Item 2, 3, 4 and 5 are not applicable. Item 6. Exhibits and Reports on Form 8-K A. Exhibits SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated: Exhibits filed with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit numbers in prior filings are hereby incorporated herein by reference and made a part hereof. B. Reports on Form 8-K during the third quarter 2001 were as follows: SCANA Corporation: None South Carolina Electric & Gas Company: None Public Service Company of North Carolina, Incorporated: None SCANA CORPORATION SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SCANA CORPORATION (Registrant) November 14, 2001 By: s/Mark R. Cannon ---------------------- Mark R. Cannon Controller (Principal accounting officer) SOUTH CAROLINA ELECTRIC & GAS COMPANY SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SOUTH CAROLINA ELECTRIC & GAS COMPANY ------------------------------------- (Registrant) November 14, 2001 By: s/Mark R. Cannon --------------------------------- Mark R. Cannon Controller (Principal accounting officer) PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrant) November 14, 2001 By: s/Mark R. Cannon --------------------------------- Mark R. Cannon Controller (Principal accounting officer) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 2.01 X X Agreement and Plan of Merger, dated as of February 16, 1999 as amended and restated as of May 10, 1999, by and among Public Service Company of North Carolina, Incorporated, SCANA Corporation, New Sub I, Inc. and New Sub II, Inc. (Filed as Exhibit 2.1 to Registration Statement No. 333-78227 on Form S-4) 3.01 X Restated Articles of Incorporation of SCANA as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145) 3.02 X Articles of Amendment of SCANA, dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421) 3.03 X Restated Articles of Incorporation of SCE&G, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460) 3.04 X Articles of Amendment of SCE&G dated May 22, 2001 (Filed as Exhibit 3.02 to Registration Statement No. 333-65460) 3.05 X Articles of Correction of SCE&G dated June 1, 2001 (Filed as Exhibit 3.03 to Registration Statement No. 333-65460) 3.06 X Articles of Amendment of SCE&G dated June 14, 2001 (Filed as Exhibit 3.04 to Registration Statement No. 333-65460) 3.07 X Articles of Amendment of SCE&G dated August 30, 2001 (Filed herewith) 3.08 X Articles of Incorporation of PSNC (formerly New Sub II, Inc.) dated February 12, 1999 (Filed as Exhibit 3.01 to Registration Statement No. 333-45206) 3.09 X Articles of Amendment of PSNC (formerly New Sub II, Inc.) as adopted on February 10, 2000 (Filed as Exhibit 3.02 to Registration Statement No. 333-45206) 3.10 X Articles of Correction of PSNC dated February 11, 2000 (Filed as Exhibit 3.03 to Registration Statement No. 333-45206) 3.11 X By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266) 3.12 X By-Laws of SCE&G as amended and adopted on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460) 3.13 X By-Laws of PSNC (formerly New Sub II, Inc.) as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-68516) 4.01 X Articles of Exchange of South Carolina Electric and Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 4.02 X Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration Statement No. 33-32107) 4.03 X X Indenture dated as of January 1, 1945, between the South Carolina Power Company and Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Filed as Exhibit 2-B to Registration Statement No. 2-26459) 4.04 X X Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture (Filed as Exhibit 2-C to Registration Statement No. 2-26459) 4.05 X X Fifth through Fifty-third Supplemental Indentures to Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements whose file numbers are set forth below December 1, 1950 Exhibit 2-D to Registration No. 2-26459 July 1, 1951 Exhibit 2-E to Registration No. 2-26459 June 1, 1953 Exhibit 2-F to Registration No. 2-26459 June 1, 1955 Exhibit 2-G to Registration No. 2-26459 November 1, 1957 Exhibit 2-H to Registration No. 2-26459 September 1, 1958 Exhibit 2-I to Registration No. 2-26459 September 1, 1960 Exhibit 2-J to Registration No. 2-26459 June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 June 1, 1966 Exhibit 2-M to Registration No. 2-26459 June 1, 1967 Exhibit 2-N to Registration No. 2-29693 September 1, 1968 Exhibit 4-O to Registration No. 2-31569 June 1, 1969 Exhibit 4-C to Registration No. 33-38580 December 1, 1969 Exhibit 4-O to Registration No. 2-35388 June 1, 1970 Exhibit 4-R to Registration No. 2-37363 March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324 January 1, 1972 Exhibit 2-B to Registration No. 33-38580 July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291 May 1, 1975 Exhibit 4-C to Registration No. 33-38580 July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908 February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304 December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936 March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662 May 1, 1977 Exhibit 4-C to Registration No. 33-38580 February 1, 1978 Exhibit 4-C to Registration No. 33-38580 June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653 April 1, 1979 Exhibit 4-C to Registration No. 33-38580 June 1, 1979 Exhibit 2-A-3 to Registration No. 33-38580 April 1, 1980 Exhibit 4-C to Registration No. 33-38580 June 1, 1980 Exhibit 4-C to Registration No. 33-38580 December 1, 1980 Exhibit 4-C to Registration No. 33-38580 April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 September 1, 1987 Exhibit 4-D to Registration No. 33-49421 January 1, 1989 Exhibit 4-D to Registration No. 33-49421 January 1, 1991 Exhibit 4-D to Registration No. 33-49421 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 May 1, 1999 Exhibit 4.04 to Registration No. 333-86387 4.06 X X Indenture dated as of April 1, 1993 from South Carolin Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421) 4.07 X X First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421) 4.08 X X Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955) 4.09 X X Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.03 to Registration Statement No. 333-49960) 4.10 X X Certificate of Trust of SCE&G Trust I (Filed as Exhibit 4.04 to Registration Statement No. 333-49960) 4.11 X X Junior Subordinated Indenture for SCE&G Trust I (Filed as Exhibit 4.05 to Registration Statement No.333-49960) 4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as Exhibit 4.06 to Registration Statement No. 333-49960) 4.13 X X Amended and Restated Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.07 to Registration Statement No. 333-49960) 4.14 X X Indenture dated as of January 1, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206) 4.15 X X First Supplemental Indenture dated as of January 1, 1996, between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.09 to Registration Statement No. 333-45206) 4.16 X X Second Supplemental Indenture dated as of December 15, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.10 to Registration Statement No. 333-45206) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 4.17 X X Third Supplemental Indenture dated as of February 10, 2000 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.11 to Registration Statement No. 333-45206) 4.18 X X Fourth Supplemental Indenture dated as of February 12, 2001 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.05 to Registration Statement No. 333-68516) 4.19 X PSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516) 10.01 X SCANA Executive Deferred Compensation Plan as amended July 1, 2001 (Filed herewith) 10.01a X SCANA Voluntary Deferral Plan as amended through October 21, 1997 (Filed as Exhibit 10.01 to Registration Statement No. 333-49960) 10.01b X SCANA Key Employee Retention Plan as amended and restated effective as of October 21, 1997 (Filed as Exhibit 10.02 to Registration Statement No. 333-49960) 10.01c X Resolution by SCANA Corporation Board of Directors amending the SCANA Key Employee Retention Plan, adopted August 2, 2001 (Filed herewith) 10.02 X SCANA Supplemental Executive Retirement Plan as amended July 1, 2000 (Filed herewith) 10.03 X SCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed herewith) 10.03a X SCANA Supplementary Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed herewith) 10.04 X SCANA Performance Share Plan as amended and restated effective January 1, 1998 (Filed as Exhibit 10 (e) to Registration Statement No. 333-86803) 10.05 X SCANA Long-Term Equity Compensation Plan dated January 2000 filed as Exhibit 4.04 to Registration Statement No. 333-37398) 10.06 X Description of SCANA Whole Life Option (Filed as Exhibit 10-F to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809) 10.07 X Description of SCANA Corporation Executive Annual Incentive Plan (Filed as Exhibit 10-G to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809) 10.08 X SCANA Corporation Director Compensation and Deferral Plan effective January 1, 2001 (Filed as Exhibit 10.05 to Registration Statement No. 333-49960) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 10.09 X Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206) 10.10 X Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206) 10.11 X Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206) 10.12 X Amended Construction, Operation and Maintenance Agreement by and between Cardinal Operating Company and Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.04 to Registration Statement No. 333-45206) 10.13 X Form of Severance Agreement between PSNC and its Executive Officers (Filed as Exhibit 10.05 to Registration Statement No. 333-45206) 10.14 X Service Agreement between PSNC and SCANA Services, Inc., effective April 1, 2000 (Filed as Exhibit 10.06 to Registration Statement No. 333-45206) 10.15 X Service Agreement between SCE&G and SCANA Services, Inc., effective April 1, 2001 (Filed herewith)