-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IXwW7M+kw4LjD5Z4ziiLqQ/ej4gaKiohUH/5fFMWM+C0IbRyot/cfA9gL8Gq6Avc sBN/nbRtmn2zTLsXGSUxVw== 0000754737-03-000089.txt : 20030808 0000754737-03-000089.hdr.sgml : 20030808 20030808162013 ACCESSION NUMBER: 0000754737-03-000089 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20030630 FILED AS OF DATE: 20030808 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NORTH CAROLINA INC CENTRAL INDEX KEY: 0000081025 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 562128483 STATE OF INCORPORATION: SC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-11429 FILM NUMBER: 03832105 BUSINESS ADDRESS: STREET 1: 1426 MAIN STREET CITY: COLUMBIA STATE: SC ZIP: 29201 BUSINESS PHONE: 8032179188 MAIL ADDRESS: STREET 1: 1426 MAIN STREET CITY: COLUMBIA STATE: SC ZIP: 29201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTH CAROLINA ELECTRIC & GAS CO CENTRAL INDEX KEY: 0000091882 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 570248695 STATE OF INCORPORATION: SC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03375 FILM NUMBER: 03832106 BUSINESS ADDRESS: STREET 1: 1426 MAIN ST CITY: COLUMBIA STATE: SC ZIP: 29201 BUSINESS PHONE: 8032179000 MAIL ADDRESS: STREET 1: 1426 MAIN ST CITY: COLUMBIA STATE: SC ZIP: 29201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SCANA CORP CENTRAL INDEX KEY: 0000754737 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 570784499 STATE OF INCORPORATION: SC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-08809 FILM NUMBER: 03832103 BUSINESS ADDRESS: STREET 1: 1426 MAIN ST STREET 2: MAIL CODE - 051 CITY: COLUMBIA STATE: SC ZIP: 29201 BUSINESS PHONE: 8032179000 MAIL ADDRESS: STREET 1: 1426 MAIN STREET STREET 2: MAIL CODE - 051 CITY: COLUMBIA STATE: SC ZIP: 29218 10-Q 1 secondqtr03.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 June 30, 2003 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 Carolina Corporation) 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. SCANA Corporation Yes X No South Carolina Electric & Gas Company Yes X No Public Service Company of North Carolina, Incorporated Yes X No Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes X No South Carolina Electric & Gas Company Yes No X Public Service Company of North Carolina, Incorporated Yes No X Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Description of Shares Outstanding Registrant Common Stock at July 31, ---------- ------------ ------------ 2003 SCANA Corporation Without Par Value 110,922,883 South Carolina Electric & Gas Company $4.50 Par Value 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 June 30, 2003 and December 31, 2002 ......................... 4 Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2003 and 2002............. 6 Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2003 and 2002............. 7 Condensed Consolidated Statements of Comprehensive Income (Loss) for the Periods Ended June 30, 2003 and 2002........................................................................... 8 Notes to Condensed Consolidated Financial Statements..................................................... 9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................ 21 Item 3. Quantitative and Qualitative Disclosures About Market Risk................................................... 29 Item 4. Controls and Procedures...................................................................................... 31 South Carolina Electric & Gas Company Financial Section................................................................ 32 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002 ......................... 33 Condensed Consolidated Statements of Income for the Periods Ended June 30, 2003 and 2002................. 35 Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2003 and 2002............. 36 Notes to Condensed Consolidated Financial Statements..................................................... 37 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations......................... 44 Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................................... 50 Item 4. Controls and Procedures....................................................................................... 50 Public Service Company of North Carolina, Incorporated Financial Section............................................... 51 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002 ......................... 52 Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2003 and 2002............. 53 Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2003 and 2002............. 54 Condensed Consolidated Statements of Comprehensive Income (Loss) for the Periods Ended June 30, 2003 and 2002.......................................................................... 55 Notes to Condensed Consolidated Financial Statements...................................................... 56 Item 2. Management's Narrative Analysis of Results of Operations...................................................... 60 Item 4. Controls and Procedures....................................................................................... 62 PART II. OTHER INFORMATION Item 1. Legal Proceedings............................................................................................. 63 Item 4. Submission of Matters to a Vote of Security Holders........................................................... 64 Item 6. Exhibits and Reports on Form 8-K.............................................................................. 65 Signatures............................................................................................................. 66 Exhibit Index.......................................................................................................... 67 Certifications Required by Rule 13a-14 ................................................................................ 72 Certifications Pursuant to 18 U.S.C. Section 1350...................................................................... 78
SCANA CORPORATION FINANCIAL SECTION
PART I. FINANCIAL INFORMATION Item 1. Financial Statements SCANA CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - ------------------------------------------------------------------------------- ------------------ ------------------ June 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------- ------------------ ------------------ Assets Utility Plant: Electric $5,361 $5,228 Gas 1,631 1,593 Other 197 184 - ------------------------------------------------------------------------------- ------------------ ------------------ Total 7,189 7,005 Accumulated depreciation and amortization (2,577) (2,476) - ------------------------------------------------------------------------------- ------------------ ------------------ Total 4,612 4,529 Construction work in progress 914 677 Nuclear fuel, net of accumulated amortization 28 38 Acquisition adjustments, net of accumulated amortization 230 230 - ------------------------------------------------------------------------------- ------------------ ------------------ Utility Plant, Net 5,784 5,474 - ------------------------------------------------------------------------------- ------------------ ------------------ Nonutility Property, Net of Accumulated Depreciation 93 95 Investments 220 231 - ------------------------------------------------------------------------------- ------------------ ------------------ - ------------------------------------------------------------------------------- ------------------ ------------------ Nonutility Property and Investments, Net 313 326 - ------------------------------------------------------------------------------- ------------------ ------------------ - ------------------------------------------------------------------------------- ------------------ ------------------ Current Assets: Cash and temporary investments 220 374 Receivables, net of allowance for uncollectible accounts of $21 and $17 377 478 Receivables - affiliated companies 15 8 Inventories (at average cost): Fuel 147 166 Materials and supplies 58 61 Emission allowances 9 10 Prepayments 44 40 Deferred income taxes, net 8 - - ------------------------------------------------------------------------------- ------------------ ------------------ Total Current Assets 878 1,137 - ------------------------------------------------------------------------------- ------------------ ------------------ Deferred Debits: Environmental 21 27 Nuclear plant decommissioning - 87 Assets held in trust, net-nuclear decommissioning 36 - Pension asset, net 266 265 Other regulatory assets 331 292 Other 167 146 - ------------------------------------------------------------------------------- ------------------ ------------------ Total Deferred Debits 821 817 - ------------------------------------------------------------------------------- ------------------ ------------------ Total $7,796 $7,754 =============================================================================== ================== ================== - ------------------------------------------------------------------------------------ ------------------- ----------------- June 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------------ ------------------- ----------------- Capitalization and Liabilities Stockholders' Investment: Common equity $2,258 $2,177 Preferred stock (Not subject to purchase or sinking funds) 106 106 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Stockholders' Investment 2,364 2,283 Preferred Stock, net (Subject to purchase or sinking funds) 9 9 SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G - 50 Long-Term Debt, net 2,930 2,834 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Capitalization 5,303 5,176 - ------------------------------------------------------------------------------------ ------------------- ----------------- Current Liabilities: Short-term borrowings 212 209 Current portion of long-term debt 403 413 Accounts payable 222 354 Accounts payable - affiliated companies 13 8 Customer deposits 39 39 Taxes accrued 88 78 Interest accrued 55 52 Dividends declared 41 39 Deferred income taxes, net - 4 Other 52 77 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Current Liabilities 1,125 1,273 - ------------------------------------------------------------------------------------ ------------------- ----------------- Deferred Credits: Deferred income taxes, net 754 747 Deferred investment tax credits 115 118 Reserve for nuclear plant decommissioning - 87 Asset retirement obligation - nuclear plant 114 - Postretirement benefits 136 131 Regulatory liabilities 137 114 Other 112 108 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Deferred Credits 1,368 1,305 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total $7,796 $7,754 ==================================================================================== =================== ================= See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - -------------------------------------------------------------------- --------------------------- --------------------------- Three Months Ended Six Months Ended June 30, June 30, Millions of dollars, except per share amounts 2003 2002 2003 2002 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Operating Revenues: Electric $356 $349 $692 $651 Gas - regulated 193 155 620 451 Gas - nonregulated 177 145 483 369 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Total Operating Revenues 726 649 1,795 1,471 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Operating Expenses: Fuel used in electric generation 80 92 161 166 Purchased power 16 16 26 21 Gas purchased for resale 293 234 865 613 Other operation and maintenance 141 131 285 258 Depreciation and amortization 60 55 120 108 Other taxes 36 32 70 63 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Total Operating Expenses 626 560 1,527 1,229 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Operating Income 100 89 268 242 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Other Income: Other income, including allowance for equity funds used during construction of $5, $6, $9 and $13 17 20 33 37 Gain on sale of investments and assets 56 15 56 31 Impairment of investments (7) (11) (7) (255) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Total Other Income (Expense) 66 24 82 (187) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 166 113 350 55 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $2, $3, $5 and $7 51 51 102 102 Dividend Requirement of SCE&G - Obligated Mandatorily Redeemable Preferred Securities 1 1 2 2 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income (Loss) Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 114 61 246 (49) Income Tax Expense (Benefit) 38 19 84 (21) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income (Loss) Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 76 42 162 (28) Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 2 2 4 4 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income (Loss) Before Cumulative Effect of Accounting Change 74 40 158 (32) Cumulative Effect of Accounting Change, net of taxes - - - (230) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Net Income (Loss) $74 $40 $158 $(262) ==================================================================== =============== =========== ============ ============== ==================================================================== =============== =========== ============ ============== Basic and Diluted Earnings (Loss) Per Share of Common Stock: Before Cumulative Effect of Accounting Change $.67 $.38 $1.42 $(.30) Cumulative Effect of Accounting Change, Net of Taxes - - - (2.20) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Basic and Diluted Earnings (Loss) Per Share $.67 $.38 $1.42 $(2.50) ==================================================================== =============== =========== ============ ============== ==================================================================== =============== =========== ============ ============== Weighted Average Shares Outstanding (millions) 110.8 104.7 110.8 104.7 See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - --------------------------------------------------------------------------------------- ---------------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Operating Activities: Net income (loss) $158 $(262) Adjustments to reconcile net income (loss) to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - 230 Depreciation and amortization 125 113 Amortization of nuclear fuel 12 7 Gain on sale of investments and assets (56) (31) Hedging activities (3) 39 Impairment on investments 7 255 Allowance for funds used during construction (14) (20) Over (under) collection, fuel adjustment clauses 21 (21) Changes in certain assets and liabilities: (Increase) decrease in receivables, net 94 44 (Increase) decrease in inventories 23 25 (Increase) decrease in prepayments (4) (10) (Increase) decrease in pension asset (1) (13) (Increase) decrease in other regulatory assets (17) (5) Increase (decrease) in deferred income taxes, net (4) (136) Increase (decrease) in regulatory liabilities 21 17 Increase (decrease) in postretirement benefits 5 5 Increase (decrease) in accounts payable (127) (38) Increase (decrease) in taxes accrued 10 (43) Increase (decrease) in interest accrued 3 11 Changes in other assets (4) 8 Changes in other liabilities (7) 13 - --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Provided From Operating Activities 242 188 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (380) (269) Proceeds from sale of investments and assets 65 336 Increase in nonutility property (4) (7) Investments in affiliates (8) (20) - --------------------------------------------------------------------------------------- ------------------ --------------- - --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Provided From (Used For) Investing Activities (327) 40 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 495 295 Issuance of notes and loans 2 397 Issuance of common stock upon exercise of stock options 2 - Repayments: Mortgage bonds (250) (104) Notes and loans (171) (605) SCE&G Trust I Preferred Securities (50) - Payment of deferred financing costs (21) - Dividends and distributions: Common stock (75) (66) Preferred stock (4) (4) Short-term borrowings, net 3 48 - --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Used For Financing Activities (69) (39) - --------------------------------------------------------------------------------------- ------------------ --------------- Net Increase (Decrease) In Cash and Temporary Investments (154) 189 Cash and Temporary Investments, January 1 374 192 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash and Temporary Investments, June 30 $220 $381 ======================================================================================= ================== =============== Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $5 and $7) $100 $89 - Income taxes 24 105 Noncash Investing and Financing Activities: Unrealized gain (loss) on securities available for sale, net of tax - 29 See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - ------------------------------------------------------------------------------------- ----------------------- Three Months Ended Six Months Ended June 30, June 30, Millions of dollars 2003 2002 2003 2002 - ------------------------------------------------------------------------- ----------- ---------- ------------ - ------------------------------------------------------------------------- ----------- ---------- ------------ Net Income (Loss) $74 $40 $158 $(262) Other Comprehensive Income (Loss), net of tax: Unrealized gains (losses) on securities available for sale - (64) - 29 Unrealized gains (losses) on hedging activities - 3 (2) 27 - ------------------------------------------------------------------------- ----------- ---------- ------------ Total Comprehensive Income (Loss) (1) $74 $(21) $156 $(206) ========================================================================= =========== ========== ============
(1) Accumulated other comprehensive income (loss) of the Company totaled $(0.4) million and $1.0 million as of June 30, 2003 and December 31, 2002, respectively. See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2003 (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, 2002. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Operations 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, 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 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 June 30, 2003, approximately $352 million and $137 million of regulatory assets and liabilities, respectively, as shown below. June 30, December 31, Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Accumulated deferred income taxes, net $95 $95 Under-collections - fuel adjustment clauses 39 61 Deferred environmental remediation costs 21 27 Asset retirement obligation - nuclear decommissioning 51 - Deferred non-conventional fuel tax benefits, net (52) (40) Storm damage reserve (34) (32) Franchise agreements 64 65 Other 31 29 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $215 $205 ================================================================================ Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under-collections - fuel adjustment clauses represent amounts under-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings. Deferred environmental remediation costs represent costs associated with the assessment and clean up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by South Carolina Electric & Gas Company (SCE&G) are being recovered through rates, and such costs, totaling approximately $12 million, are expected to be fully recovered by the end of 2005. A portion of the costs incurred at sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy) is also being recovered through rates, and management believes the remaining costs of approximately $7.6 million will be recoverable in the future. Amounts incurred to date that have not been recovered through gas rates at PSNC Energy are approximately $1.3 million. (See Note 3.) Asset retirement obligation - nuclear decommissioning represents the regulatory asset associated with the legal obligation of decommissioning and dismantling V. C. Summer Nuclear Station (Summer Station) as required in SFAS 143, "Accounting for Asset Retirement Obligations." (See Note 1B). Deferred non-conventional fuel tax benefits represent the deferral of partnership losses and other expenses, offset by the accumulated deferred income tax credits associated with two SCE&G partnerships involved in converting coal to alternate fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a ten-year period. The accumulated storm damage reserve can be applied to offset actual storm damage costs in excess of $2.5 million in a calendar year. Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are not earning a return, but are being amortized through cost of service over the next 15 years. The SCPSC and the NCUC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC or the NCUC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to SCPSC or NCUC approval. 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 adversely affected. B. New Accounting Standards The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. In connection with this implementation, the Company performed a valuation analysis of its investment in South Carolina Pipeline Corporation (SCPC) using a discounted cash flow analysis and of PSNC Energy using an independent appraisal. The analysis of the investment in PSNC Energy indicated that the carrying amount of PSNC Energy's acquisition adjustment exceeded its fair value by approximately $230 million, or $2.20 loss per share. The resulting impairment charge is reflected on the Condensed Consolidated Statement of Operations as the cumulative effect of an accounting change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. The Company performed an annual evaluation as of January 1, 2003 and no further impairment was indicated. The Company adopted SFAS 143 effective January 1, 2003. SFAS 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. As of December 31, 2002, prior to the adoption of SFAS 143, the Company carried deferred debits and deferred credits each totaling approximately $87 million related to the decommissioning and dismantling of Summer Station and the funding thereof. Effective January 1, 2003, in connection with the measurement of the ARO upon the adoption of SFAS 143, the amounts reflected within these regulatory assets and liabilities were recharacterized. The following table presents such recharacterized amounts related to the decommissioning obligation and the funding thereof as recorded in the condensed consolidated balance sheet as of June 30, 2003, and the pro forma amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been adopted at the beginning of 2001. As of June 30, December 31, December 31, Millions of dollars 2003 2002 2001 - ------------------- Actual Proforma Proforma Assets: Within electric plant $40 $40 $40 Within accumulated depreciation (13) (13) (12) Assets held in trust (net) - nuclear decommissioning 36 39 35 Within other regulatory assets 51 45 42 ------------- ---------------- ------- ------------- ---------------- ------- Total $114 $111 $105 ============= ================ ======= ============= ================ ======= Liabilities: Asset retirement obligation - nuclear plant decommissioning $114 $111 $105 ============ ============== =========== Proforma net income (loss) and earnings (loss) per share for periods prior to the adoption of SFAS 143 would not differ from amounts actually recorded during these periods. In addition to the ARO for Summer Station, the Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated. The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145. The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146. The Company adopted the disclosure provisions of SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," effective January 1, 2003. SFAS 148 requires prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 148. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, " Accounting for Derivative Instruments and Hedging Activities". SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS 149 is not expected to have a material impact on the Company's results of operations, cash flows or financial position. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150. C. Equity Compensation Plan Under the SCANA Corporation Long-Term Equity Compensation Plan (the "Plan"), certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, "Accounting for Stock Issued to Employees" and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation" and, effective January 1, 2003, the disclosure provisions of SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." At June 30, 2003, options issued and outstanding under the Plan totaled approximately 1.6 million. All options were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates; therefore, no compensation expense has been recognized in connection with such grants. If the Company had determined compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings (loss) per share would have been as presented below:
Three Months Ended Six Months Ended June 30, June 30, 2003 2002 2003 2002 ---- ---- ---- ---- Net income (loss) - as reported (millions) $74 $40 $158 $(262) Net income (loss) - pro forma (millions) $73 $40 $157 $(262) Basic and diluted earnings (loss) per share - as reported $.67 $.38 $1.42 $(2.50) Basic and diluted earnings (loss) per share - pro forma $.66 $.38 $1.41 $(2.50)
D. Earnings (Loss) Per Share Earnings (loss) 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. Affiliated Transactions SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. SCE&G had recorded as receivables from affiliated companies for these investments approximately $15.5 million and $8.5 million at June 30, 2003 and December 31, 2002, respectively. SCE&G had recorded as payables to affiliated companies for these investments approximately $13.2 million and $8.0 million at June 30, 2003 and December 31, 2002, respectively. F. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003. 2. ACCOUNTING CHANGE As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to the acquisition adjustment which had been recorded in connection with its investment in PSNC Energy. This charge is reflected on the Condensed Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1B. 3. RATE AND OTHER REGULATORY MATTERS South Carolina Electric & Gas Company (SCE&G) Electric In January 2003 the SCPSC issued an order granting SCE&G a composite increase in retail electric rates of approximately 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for 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 2002. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending. In January 2003, in conjunction with the approval of the above retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh. This reduction was effective for service rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order approving SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices and recognized the efficiency of SCE&G's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the above appeal to the Circuit Court of the SCPSC's May 2002 order. Gas SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the period January 1, 2002 through June 30, 2003 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.728 January-February 2003 $.596 January-October 2002 $.928 March-June 2003 $.728 November-December 2002 The SCPSC allows SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former 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 recorded in deferred debits. In October 2002, as a result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at June 30, 2003 of $12.3 million. Public Service Company of North Carolina, Incorporated (PSNC Energy) PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually. PSNC Energy's benchmark cost of gas in effect during the period January 1, 2002 through June 30, 2003 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.460 January-February 2003 $.300 January 2002 $.595 March 2003 $.215 February-June 2002 $.725 April-June 2003 $.350 July-October 2002 $.410 November-December 2002 On April 24, 2003 the NCUC issued an order in PSNC Energy's 2002 Annual Prudence Review. The NCUC determined that PSNC Energy's gas costs during the 12-month review period ended March 31, 2002 were reasonable and prudently incurred. The NCUC also authorized new temporary rate decrements to refund certain balances in deferred accounts. On June 2, 2003 PSNC Energy filed testimony in the 2003 Annual Prudence Review related to the 12 months ended March 31, 2003. The NCUC will hold a hearing on August 12, 2003 to review PSNC Energy's filing. A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion is expected to be completed in the spring of 2004. Through June 30, 2003 approximately $20.0 million had been spent on this project. In December 1999 the NCUC issued an order approving SCANA's acquisition of PSNC Energy. As specified in the order, PSNC Energy 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 material adverse governmental actions and force majeure events. South Carolina Pipeline Corporation (SCPC) SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In an order dated August 5, 2003 the SCPSC found that for the period April 2002 through December 2002 SCPC's gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff. 4. LONG-TERM DEBT On January 13, 2003 the Company retired at maturity $60 million of 6.05% medium-term notes. On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. On April 4, 2003 the Company redeemed $100 million of floating rate medium-term notes that were set to mature August 8, 2003. The notes were bearing interest at a rate of 2.215% when redeemed. On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net proceeds from the sale of these bonds and certain other SCE&G funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. 5. RETAINED EARNINGS The Company's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G 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 June 30, 2003 approximately $42.4 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock. 6. FINANCIAL INSTRUMENTS Investments Certain of the Company's subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market prices, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. Debt securities and preferred stock with significant debt characteristics are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. Telecommunications Investments At June 30, 2003 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held investments in the equity and debt securities of the following companies in the amounts noted in the table below.
Investee Securities Basis - ------------------ ------------------------------------------------------------- ----------------------- (Millions of dollars) Magnolia Holding 6.2 million shares nonvoting common stock $8.3 ITC^DeltaCom 566.0 thousand shares of common stock 1.1 154.2 thousand shares series A 8% preferred stock, convertible in 2005 into 2.7 million shares of common stock 12.9 Warrants to purchase 506.9 thousand shares of common stock 1.1 Knology 7.2 million shares series A preferred stock, convertible into 7.5 million shares of common stock 14.0 14.8 million shares series C preferred stock, convertible into 14.8 million shares of common stock 27.8 21.7 million shares series E preferred stock, convertible into 21.7 million shares of common stock 40.6 12% senior unsecured notes due 2009, including accrued interest 46.5
On May 9, 2003, the Company's investment in ITC Holding Company, Inc. was sold. The transaction resulted in the receipt of net after-tax cash proceeds of approximately $46 million and the receipt of an investment interest in a newly formed entity, Magnolia Holding Company LLC (Magnolia Holding). A book gain, net of tax, of approximately $37 million was realized upon this transaction. Magnolia Holding holds ownership interests in several Southeastern communications companies. ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. The common shares of ITC^DeltaCom owned by SCH have a market value of $1.7 million. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and the market value is not readily determinable. Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services.In June 2003, based upon valuation information obtained in connection with the Magnolia Holding transaction, SCH recorded impairment losses associated with the Knology investment totaling $4.8 million, net of taxes. Derivatives SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, 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 (loss), depending upon the intended use of the derivative and the resulting designation. The fair value of the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties. Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. The Company's Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure. The Risk Management Committee, which is comprised of certain officers, including the Company's Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions that are allowed. Commodities The Company uses derivative instruments to hedge anticipated future purchases 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. Instruments designated as fair value hedges are used to hedge operational storage assets. 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. The Company recognized gains of approximately $5.8 million, net of tax, as a result of qualifying cash flow hedges related to nonregulated operations during the six months ended June 30, 2003. No such gains were recognized during the three months ended June 30, 2003. The Company recognized losses of approximately $2.9 million and $21.9 million, net of tax, as a result of qualifying cash flow hedges related to nonregulated operations during the three and six months ended June 30, 2002. These gains and losses were recorded in cost of gas. The Company estimates that most of the June 30, 2003 unrealized gain balance of $0.5 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2004 and 2005 as a decrease to gas cost if market prices remain stable. As of June 30, 2003 all of the Company's cash flow hedges settle by their terms before the end of 2006. The Company recorded option premiums of $0.4 million and gains of $0.3 million, net of tax, as a result of qualifying fair value hedges during the three and six months ended June 30, 2003, respectively. The premiums and gains were recorded in cost of gas. As of June 30, 2003 all of the Company's fair value hedges settle by their terms before the end of 2003. On January 2, 2003 PSNC Energy filed a summary of its hedging program for natural gas purchases with the NCUC for informational purposes. The primary goal of the program is to reduce price volatility to firm customers. The program and any related transactions will be addressed in the NCUC's August 2003 Annual Prudence Review. Transaction fees and any gains or losses are recorded in deferred accounts for subsequent rate consideration. SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a current asset or liability. The Company also utilizes certain derivative instruments that do not qualify as hedges. The change in fair value of these derivatives is recorded in net income (loss), and was insignificant in the periods presented. Interest Rates The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable rate and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. Payments received upon termination of a swap are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. The fair value of interest rate swaps is recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. At June 30, 2003 the estimated fair value of the Company's swaps totaled $20.2 million related to combined notional amounts of $337.4 million. In anticipation of the issuance of debt, the Company also uses interest rate lock agreements to manage interest rate risk. Payments received or made upon termination of interest rate lock agreements are recorded within other deferred debits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreeement. 7. COMMITMENTS AND CONTINGENCIES 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, 2002. Commitments and contingencies at June 30, 2003 include the following: A. Lake Murray Dam Reinforcement In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through June 30, 2003 totaled approximately $105 million. 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 Summer Station, would be approximately $58.7 million per incident, but not more than $6.7 million per year. The Price-Anderson Indemnification Act expired in August 2002, but is expected to renew with only modest changes in 2003. This has no impact on SCE&G at present due to the "grandfathered" status of existing licensees that are covered under the past act until such time as it is renewed. SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) 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 $15.8 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 would 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 solely to regulated operations. South Carolina Electric & Gas Company At SCE&G, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $8.2 million at June 30, 2003. The deferral includes the estimated costs associated with the following matters. SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of June 30, 2003, SCE&G has spent approximately $18.7 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.2 million. SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from an MGP site. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. SCE&G has spent approximately $2.3 million related to all of these sites, and expects to spend an additional $5.7 million. Public Service Company of North Carolina, Incorporated PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. PSNC Energy has recorded a liability and associated regulatory asset of $7.6 million, which reflects the estimated remaining liability at June 30, 2003. Amounts incurred to date that have not been recovered through gas rates are approximately $1.3 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates. D. Long-Term Natural Gas Contract In 2001 a subsidiary of the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of the supplier and its guarantor to meet contractual obligations related to credit support provisions, the subsidiary terminated the contract. A hearing under the binding arbitration provisions of the contract is scheduled for September 2003. In initial pleadings for the hearing, the supplier demanded payment of at least $134 million in damages from the subsidiary; conversely, the subsidiary demanded payment of no less than $154 million in damages from the supplier. The Company is confident of the propriety of its actions, and the Company will vigorously pursue its position in the arbitration proceedings. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition. 8. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations. Therefore, net income is not allocated to the Electric Operations, Gas Distribution and Gas Transmission segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Accumulated depreciation is not assignable to Electric Operations and Gas Distribution segments; therefore, it is reflected as an adjustment to arrive at consolidated total assets. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation.
Disclosure of Reportable Segments (Millions of dollars) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Three Months Ended External Intersegment Operating Net Segment June 30, 2003 Revenue Revenue Income (Loss) Income (Loss) Assets - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Electric Operations $356 $1 $97 n/a $6,224 Gas Distribution 146 - (6) n/a 1,439 Gas Transmission 47 64 3 n/a 331 Retail Gas Marketing 77 - n/a $3 78 Energy Marketing 100 - n/a - 50 Telecommunications Investments - - n/a 32 183 All Other - 72 - (1) 368 Adjustments/Eliminations - (137) 6 40 (877) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Consolidated Total $726 $- $100 $74 $7,796 ================================== ============= ============== =============== ================= =============== - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Six Months Ended External Intersegment Operating Net Segment June 30, 2003 Revenue Revenue Income Income (Loss) Assets - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Electric Operations $692 $3 $181 n/a $6,224 Gas Distribution 489 - 55 n/a 1,439 Gas Transmission 131 172 8 n/a 331 Retail Gas Marketing 260 - n/a $17 78 Energy Marketing 223 - n/a (2) 50 Telecommunications Investments - - n/a 33 183 All Other - 139 - (3) 368 Adjustments/Eliminations - (314) 24 113 (877) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Consolidated Total $1,795 $- $268 $158 $7,796 ================================== ============= ============== =============== ================= =============== - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Three Months Ended External Intersegment Operating Net Segment June 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Electric Operations $349 $145 $86 n/a $5,609 Gas Distribution 102 17 (2) n/a 1,626 Gas Transmission 53 58 6 n/a 290 Retail Gas Marketing 62 - n/a $1 63 Energy Marketing 83 - n/a (2) 64 Telecommunications Investments - - n/a (3) 307 All Other - 1 - 4 536 Adjustments/Eliminations - (221) (1) 40 (827) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Consolidated Total $649 $- $89 $40 $7,668 ================================== ============= ============== =============== ================= =============== - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Six Months Ended External Intersegment Operating Net Segment June 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Electric Operations $651 $293 $174 n/a $5,609 Gas Distribution 343 18 52 n/a 1,626 Gas Transmission 108 131 (3) n/a 290 Retail Gas Marketing 218 - n/a $15 63 Energy Marketing 151 - n/a (3) 64 Telecommunications Investments - - - (153) 307 All Other - 3 - 3 536 Adjustments/Eliminations - (445) 19 (124) (827) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Consolidated Total $1,471 $- $242 $(262) $7,668 ================================== ============= ============== =============== ================= ===============
9. SUBSEQUENT EVENTS On July 1, 2003 the Company retired at maturity $20 million of 6.51% medium-term notes. On July 8, 2003 the Company retired at maturity $75 million of 6.25% medium-term notes. 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, 2002. 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 and nonutility regulatory environment, (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) performance of the Company's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the United States Securities and Exchange Commission (SEC). The Company disclaims any obligation to update any forward-looking statements. COMPETITION Electric Operations In South Carolina electric restructuring efforts remain stalled, and the state legislature adjourned for the year without considering electric restructuring legislation. At the federal level, energy legislation passed both houses of Congress in 2003, though significant differences exist between the House and Senate versions. Some of the more stringent provisions of this legislation, either currently included or expected to be debated in conference committee, would require that one percent of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent by 2020, be generated from renewable energy resources. Renewable energy resources, as defined in the legislation, may exclude hydroelectric generation. Substantial penalties would be levied for failure to comply. Electric cooperatives and municipal utilities would be exempt from these requirements. The Company cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities. In July 2002 the United States Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and will attempt, in large measure, to standardize the national energy market. If implemented, the proposed rule may have a significant impact on South Carolina Electric and Gas Company's (SCE&G) access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. On April 28, 2003 FERC issued a "white paper" regarding SMD which describes how the final SMD rule will differ from the NOPR. The Company is currently evaluating FERC's action to determine potential effects on SCE&G's operations. Additional directives from FERC are expected. Gas Distribution Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact the Company's ability to retain large commercial and industrial customers on a monthly basis. Gas Transmission In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC to acquire an interest in an existing pipeline and to build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. When operational, SCG will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's pipeline will be at the site of the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. Construction of the pipeline began in March 2003, with completion expected by the end of 2003, at a cost of approximately $32 million. South Carolina Pipeline Corporation (SCPC) supplies natural gas to SCE&G, for its resale to gas distribution customers and for certain electric generation needs. SCPC also sells natural gas to large commercial and industrial customers in South Carolina, and it faces the same competitive pressures as gas distribution for these classes of customers. Retail Gas Marketing SCANA Energy continues to maintain its position as the second largest natural gas marketer in Georgia with a market share of approximately 25 percent and total customers in excess of 350,000. SCANA Energy's competitors include affiliates of other large energy companies with substantial experience in Georgia's energy market as well as several electric membership cooperatives (EMCs). SCANA's ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors. The Georgia Public Service Commission (GPSC) continues to implement provisions of the Natural Gas Consumer's Relief Act of 2002 (the Act). Among other things, the Act created a regulated provider selected through a bidding process to serve low-income and high credit risk customers. The Act also established new service quality standards and addressed assignment of interstate assets. In 2002 SCANA Energy was selected by the GPSC to serve as Georgia's regulated provider for a 2-year period. In this capacity, SCANA Energy serves low-income customers at rates subsidized by Georgia's Universal Service Fund, and extends service to high credit risk customers who have been denied service by other marketers. At June 30, 2003 approximately 24,000 of SCANA Energy's customers were being served under this program. In July 2003 the GPSC approved a joint stipulation between the GPSC staff, Atlanta Gas Light Company (AGL) and other natural gas marketers dealing with interstate asset capacity and other operational issues. The joint stipulation reduces the frequency whereby AGL can recall capacity previously released to the various gas marketers and streamlines certain gas balancing processes. Though SCANA Energy believes the joint stipulation will improve operations for the gas marketers, SCANA Energy continues to advocate an alternate plan it proposed that would assign interstate asset capacity to those gas marketers choosing assignment and approved by the GPSC. The GPSC has indicated that it intends to file a request with FERC to obtain a declaratory order on whether FERC regulation would preempt or have jurisdiction over SCANA Energy's proposal. The GPSC has not yet filed the request with FERC. After FERC issues a declaratory order, the GPSC is expected to evaluate the order and determine what action, if any, the GPSC should take on SCANA Energy's proposal. 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 and options, to manage their exposure to fluctuating commodity natural gas prices. As a part of this risk management process, at any given time, a portion of SCANA's projected natural gas needs has been purchased or otherwise placed under contract. Since SCANA Energy operates in a competitive market, it may be unable to sustain its current level of customers and/or pricing, thereby reducing expected margins and profitability. LIQUIDITY AND CAPITAL RESOURCES The Company anticipates that its contractual cash obligations 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 foreseeable future. The Company's ratio of earnings to fixed charges for the 12 months ended June 30, 2003 was 1.82. Cash requirements for SCANA's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity or gas, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, if requested. In January 2003 the Public Service Commission of South Carolina (SCPSC) issued an order granting SCE&G a composite increase in retail electric rates of approximately 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the six months ended June 30, 2003 and 2002:
- -------------------------------------------------------------------------------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------------ ------------- Net cash provided from operating activities $242 $188 Net cash used for financing activities (69) (39) Cash provided from sale of investments and assets 65 336 Funds used for investments (8) (20) Cash and temporary investments available at the beginning of the period 374 192 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $(380) $(269) Funds used for nonutility property additions (4) (7)
CAPITAL TRANSACTIONS On January 13, 2003 the Company retired at maturity $60 million of 6.05% medium-term notes. On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. On April 4, 2003 the Company redeemed $100 million of floating rate medium-term notes that were set to mature August 8, 2003. The notes were bearing interest at a rate of 2.215% when redeemed. On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net proceeds from the sale of these bonds and certain other SCE&G funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. On July 1, 2003 the Company retired at maturity $20 million of 6.51% medium-term notes. On July 8, 2003 the Company retired at maturity $75 million of 6.25% medium-term notes. CAPITAL PROJECTS In May 2002 SCE&G began construction of 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. The $450 million facility is expected to begin commercial operation in mid-2004. SCG will transport natural gas to the facility. In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through June 30, 2003 totaled approximately $105 million. In 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the above Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the initial borrowing. At June 30, 2003 SCE&G has not yet borrowed under the agreement. ENVIRONMENTAL MATTERS For information on environmental matters see Note 7C of Notes to Condensed Consolidated Financial Statements. OTHER MATTERS Nuclear Station License Extension In August 2002 SCE&G filed an application with the Nuclear Regulatory Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). If approved, the extension would allow the plant to operate through 2042. At June 30, 2003 SCE&G had capitalized approximately $9 million related to the application process and expects to capitalize an additional $3 million. SCE&G expects the extension to be issued in mid-2004. Telecommunications Investments On May 9, 2003, the Company's investment in ITC Holding Company, Inc. was sold. The transaction resulted in the receipt of net after-tax cash proceeds of approximately $46 million and the receipt of an investment interest in a newly formed entity, Magnolia Holding Company LLC, valued at approximately $8 million. A book gain, net of tax, of approximately $37 million was realized upon consummation of this transaction. Synthetic Fuel SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of June 30, 2003 is approximately $4 million, and through June 30, 2003, they have generated and passed through to SCE&G approximately $74 million in such tax credits. In addition, PrimeSouth, Inc, a non-regulated subsidiary of SCANA, operates a synthetic fuel facility for a third party and receives management fees, royalties and expense reimbursements related to these services. PrimeSouth does not benefit from any synfuel tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through SCE&G from synfuel produced and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A of Notes to Consolidated Financial Statements. On June 27, 2003 the Internal Revenue Service (IRS) announced that it is reviewing the scientific validity of certain test procedures and results that have been presented by other taxpayers as evidence that solid coal-based synthetic fuels have undergone a significant chemical change. Pending completion of this review, the IRS has suspended the issuance of Private Letter Rulings on the question of significant chemical change for requests that rely on the testing procedures and results being reviewed. After the IRS concludes its review, which may occur before the end of 2003, the IRS may seek to disallow synfuel tax credits retroactively, prospectively or both. Although one of the partnerships in which SCE&G owns an interest is currently under audit by the IRS, there have been no issues raised with respect to the validity of synthetic fuel tax credits. While SCE&G is not able to determine what conclusion the IRS will reach, to the extent the IRS disallows synfuel tax credits, there would not be a material adverse effect on the Company's or SCE&G's financial position, results of operations or cash flows. RESULTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2003 AS COMPARED TO THE CORRESPONDING PERIODS IN 2002 The following discussion of the results of operations of SCANA Corporation and its subsidiaries (the Company) includes a non-GAAP measure, net earnings from operations per share, which excludes from net income (loss) (i) the cumulative effects of mandated changes in accounting principles and (ii) the effects of sales of certain assets and investments and impairment charges related to certain investments. Management considers net earnings from operations to be a relevant measure in assessing the Company's fundamental earnings in that it provides investors with improved transparency of financial information and more meaningful comparability of period-over-period analysis. Earnings Per Share Net earnings from operations per share of common stock for the second quarter and year to date periods ended June 30, 2003 and 2002 were as follows:
- ------------------------------------------------------------------------------------------- ------------------------- Second Quarter Year to Date 2003 2002 2003 2002 - ------------------------------------------------------------------------------ ------------ ------------ ------------ Earnings (loss) per share $.67 $.38 $1.42 $(2.50) Less: Realized gain from sale of telecommunications investments .33 - .33 .10 Investment impairments (.04) (.07) (.04) (1.59) Sale of assets - .09 - .09 Cumulative effect of accounting change, net of taxes - - - (2.20) - ------------------------------------------------------------------------------ ------------ ------------ ------------ Net earnings from operations per share $.38 $.36 $1.13 $1.10 ============================================================================== ============ ============ ============
Second Quarter 2003 vs 2002 Net earnings from operations per share increased $.02 primarily due to improved electric margins of $.12 and improved gas margins of $.06. These factors were partially offset by higher operation and maintenance expenses of $.06, higher property taxes of $.02, higher depreciation and amortization expense of $.03 and the dilutive effect of additional shares outstanding of $.04. Earnings per share for 2003 includes a gain of $.33 per share in connection with the sale of ITC Holding shares and the receipt of an investment interest in a newly formed entity (Magnolia Holding) in May 2003. In the second quarter of 2003 the Company recorded an impairment charge of $.04 per share related to the Knology preferred stock investment. In April 2002 the Company recorded a $.09 per share gain from the sale of a subsidiary's radio service network. In June 2002 the Company recorded an impairment write-down of $.07 per share related to the other than temporary decline in market value of the Company's investment in Deutsche Telekom AG (DTAG). Year to Date 2003 vs 2002 Net earnings from operations per share increased $.03 primarily due to higher electric margins of $.24 and higher gas margins of $.18. These factors were partially offset by higher operations and maintenance expenses of $.16, higher depreciation and amortization expenses of $.07, higher property taxes of $.04, the dilutive effect of additional shares outstanding of $.08 and lower AFC of $.03. Year to date earnings (loss) per share include the items described in the second quarter above. In addition, earnings (loss) per share for 2002 include a gain of $.10 per share in connection with the sale of DTAG shares in March 2002. In March 2002 the Company also recorded an impairment write-down of $1.52 per share related to the other than temporary decline in market value of the Company's investment in DTAG and the $0.07 impairment described above in the second quarter. Also, as required by SFAS 142 the Company recorded an impairment charge of $2.20 per share, effective January 1, 2002, related to the acquisition adjustment associated with Public Service Company of North Carolina, Incorporated (PSNC Energy). The charge was recorded as the cumulative effect of an accounting change. Pension Income For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income for 2003 decreased significantly compared to corresponding periods in 2002 primarily as a result of declines in the value of investments through 2002. Pension income during these periods was recorded on the Company's financial statements as follows:
- ------------------------------------------------------------------------------------ ------------------- Second Quarter Year to Date Millions of dollars 2003 2002 2003 2002 - ------------------------------------------------------------------------ ----------- --------- --------- - ------------------------------------------------------------------------ ----------- --------- --------- Income Statement Impact: (Increase) decrease in employee benefit costs $(1.2) $3.3 $(2.3) $6.9 Increase in other income 1.9 1.8 3.9 3.9 Balance Sheet Impact: (Increase) decrease in capital expenditures (0.3) 1.0 (0.6) 1.9 (Increase) decrease in amount due to Summer Station co-owner (0.1) 0.3 (0.1) 0.6 - ------------------------------------------------------------------------ ----------- --------- --------- - ------------------------------------------------------------------------ ----------- --------- --------- Total Pension Income $0.3 $6.4 $0.9 $13.3 ======================================================================== =========== ========= =========
Allowance for Funds Used During Construction (AFC) AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. The decrease in AFC for the three and six months ended June 30, 2003 is primarily the result of the completion of the Urquhart Station repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased construction expenditures related to the Jasper County Generating Station project in 2003 and the Lake Murray Dam project (see discussion at CAPITAL PROJECTS). Dividends Declared The Company's Board of Directors has declared the following dividends on common stock during 2003: - -------------------- -------------------- -------------------- ---------------- Declaration Date Dividend Per Share Record Date Payment Date - -------------------- -------------------- -------------------- ---------------- February 20, 2003 $.345 March 10, 2003 April 1, 2003 May 1, 2003 $.345 June 10, 2003 July 1, 2003 July 31, 2003 $.345 September 10, 2003 October 1, 2003 - -------------------- -------------------- -------------------- ---------------- Electric Operations Electric Operations is comprised of the electric portion of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company (Fuel Company). Changes in the electric operations sales margins were as follows:
------------------------------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ------------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------------- Operating revenues $356.3 $348.5 $7.8 2.2% $692.3 $651.1 $41.2 6.3% Less: Fuel used in generation 80.0 91.5 (11.5) (12.6%) 160.8 165.9 (5.1) (3.1%) Purchased power 15.6 16.3 (0.7) (4.3%) 26.1 21.4 4.7 22.0% ------------------------------------------------------------------ --------------------------------- Margin $260.7 $240.7 $20.0 8.3% $505.4 $463.8 $41.6 9.0% =========================================================================================================================
Second Quarter 2003 vs 2002 Margin increased by $21.3 million due to the increase in retail electric base rates approved in January 2003 and by $7.4 million due to customer growth and increased consumption. These increases were partially offset by $7.9 million due to less favorable weather. Fuel used in generation and purchased power decreased due to milder weather that resulted in a 1.6% decline in total kilowatt-hour sales. Year to Date 2003 vs 2002 Margin increased by $30.1 million due to the increase in retail electric base rates approved in January 2003 and by $13.8 million due to customer growth and increased consumption. These increases were partially offset by $2.3 million due to the effects of less favorable weather. Fuel used in generation decreased and purchased power increased due to several planned outages at steam plants during the first quarter of 2003. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy. Changes in the gas distribution sales margins, including transactions with affiliates, were as follows:
- -------------------------------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - -------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------- Operating revenues $145.6 $102.5 $43.1 42.0% $488.9 $343.5 $145.4 42.3% Less: Gas purchased for resale 102.3 60.9 41.4 68.0% 333.8 201.0 132.8 66.1% - ------------------------------------------------------------------- ---------------------------------- Margin $43.3 $41.6 $1.7 4.1% $155.1 $142.5 $12.6 8.8% ==========================================================================================================================
Second Quarter 2003 vs 2002 Margin increased primarily due to increased recovery of environmental remediation expenses of $0.3 million (offset in operations and maintenance) and customer growth and increased consumption of $2.8 million, partially offset by a decrease in industrial usage of $1.4 million due to an unfavorable competitive position of natural gas relative to alternate fuels. Year to Date 2003 vs 2002 Margin increased primarily due to customer growth at PSNC Energy (2.8%) and SCE&G (1.3%) and increased recovery of environmental remediation expenses of $1.6 million (offset in operations and maintenance), partially offset by a second quarter decrease in industrial usage of $2.3 million due to an unfavorable competitive position of natural gas relative to alternate fuels. Gas Transmission Gas Transmission is comprised of the operations of SCPC. Changes in the gas transmission sales margins, including transactions with affiliates, were as follows:
- ---------------------------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - ---------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------- Operating revenues $110.1 $110.9 $(0.8) (0.7%) $302.5 $239.0 $63.5 26.6% Less: Gas purchased for resale 99.1 98.4 0.7 0.7 278.4 227.0 51.4 22.6% - --------------------------------------------------------------- ---------------------------------- ---------------------------------- Margin $11.0 $12.5 $(1.5) (12.0%) $24.1 $12.0 $12.1 * ========================================================================================================================== *Greater than 100%
Second Quarter 2003 vs 2002 Margin decreased primarily due to an unfavorable competitive position of natural gas relative to alternate fuels and decreased demand for natural gas as a fuel for electric generation due to milder weather. Year to Date 2003 vs 2002 Margin increased primarily due to the favorable competitive position of natural gas relative to alternate fuels in the first quarter of $13.6 million, partially offset by the unfavorable competitive position of natural gas relative to alternate fuels in the second quarter of $1.5 million. Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy. Changes in Retail Gas Marketing revenues and net income (loss) were as follows: - -------------------------------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - -------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------- Operating revenues $76.5 $62.0 $14.5 23.4% $260.2 $218.2 $42.0 19.2% Net income (loss) 3.4 (0.3) 3.7 * 16.6 13.4 3.2 23.9% ========================================================================================================================== *Greater than 100%
Second Quarter 2003 vs 2002 Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $5.3 million partially offset by increased bad debt expense of $0.6 million and increased interest and operating expenses of $0.3 million. Year to Date 2003 vs 2002 Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $6.0 million partially offset by increased bad debt expense of $0.7 million, increased interest expense of $0.5 million and higher operating expense of $0.8 million. 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) were as follows:
- ---------------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - ---------------------------------------------------------------------------------------------------------- ----------------------------------------------------- Operating revenues $100.6 $82.6 $18.0 21.8% $223.0 $150.5 $72.5 48.2% Net income (loss) 0.1 (1.1) 1.2 * (1.7) (2.0) 0.3 (15.0%) ========================================================================================================== *Greater than 100%
Second Quarter 2003 vs 2002 Operating revenues increased primarily as a result of increased commodity natural gas prices. Net income increased primarily due to higher margins. Year to Date 2003 vs 2002 Operating revenues increased primarily as a result of increased commodity natural gas prices. Net loss decreased primarily as a result of lower operating and interest expenses of $2.2 million partially offset by lower margins of $1.9 million. Other Operating Expenses
Changes in other operating expenses were as follows: - ------------------------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - ------------------------------------------------------------------------------------------------------------------- Other operation and maintenance $141.0 $131.4 $9.6 7.3% $285.2 $257.8 $27.4 10.6% Depreciation and amortization 60.3 54.7 5.6 10.2% 120.2 108.4 11.8 10.9% Other taxes 35.3 32.1 3.2 10.0% 69.8 63.3 6.5 10.3% - ---------------------------------------------------------------- -------------------------------- Total $236.6 $218.2 $18.4 8.4% $475.2 $429.5 $45.7 10.6% ===================================================================================================================
Second Quarter 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $4.5 million, increased labor and benefit costs of $2.8 million and increased healthcare costs of $1.8 million. Depreciation and amortization increased by $4.0 million due to normal net property charges and by $1.6 million due to completion of the Urquhart Station repowering project in June 2002. Other taxes increased primarily due to increased property taxes. Year to Date 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $9.2 million, increased labor and benefits costs of $6.2 million, increased healthcare cost of $4.2 million, increased environmental remediation costs of $1.6 million, increased other operating expenses for electric generation and transmission of $2.5 million and increased bad debt expense of $1.3 million. Depreciation and amortization increased by $7.6 million due to normal net property additions and by $4.2 million due to the completion of the Urquhart Station repowering project in June 2002. Other taxes increased primarily due to increased property taxes. Other Income (Expense) Other income for the second quarter and year to date 2003 vs 2002, including AFC, increased primarily due to the gain on sale of assets and investments offset by the impairment of investments as discussed at Earnings Per Share. In addition, other income decreased due to a reduction in AFC due to completion of the Urquhart Station Repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by the Jasper County Generating Station project and Lake Murray Dam Project. Interest Expense Second Quarter 2003 vs 2002 Interest expense remained unchanged due to lower interest rates of $7.5 million offset by $7.3 million due to increased debt and lower AFC. Year to Date 2003 vs 2002 Interest expense remained unchanged due to lower interest rates of $9.4 million, offset by $9.8 million due to increased debt and lower AFC. Income Taxes Income taxes increased primarily as a result of changes in Other Income (Expense) as discussed at Earnings Per Share. Item 3. Quantitative and Qualitative Disclosures About Market Risk All financial instruments held by the Company described below are held for purposes other than trading. Interest rate risk - The table below provides information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.
As of June 30, 2003 Expected Maturity Date - ------------------- ---------------------- Millions of dollars There- Fair Liabilities 2003 2004 2005 2006 2007 after Total Value - --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- -------------- - --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- -------------- Long-Term Debt: Fixed Rate ($) 251.0 202.1 197.0 177.3 71.3 2,424.2 3,322.9 3,406.8 Average Fixed Interest Rate (%) 6.39 7.51 7.37 8.58 6.94 6.39 6.64 Variable Rate ($) 150.0 150.0 149.3 Average Variable Interest Rate (%) 1.94 1.94 Interest Rate Swaps: Pay Variable/Receive Fixed ($) 4.3 57.5 3.2 3.2 28.2 241.0 337.4 20.17 Average Pay Interest Rate (%) 7.20 6.10 4.29 4.29 4.56 3.03 3.76 Average Receive Interest Rate (%) 10.0 7.70 8.75 8.75 7.11 6.21 6.63
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. At June 30, 2003 the Company held investments in the 12% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $46 million. As these notes are not actively traded, determination of their fair value is not practicable. Commodity price risk - The following table provides information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value represents quoted market prices.
As of June 30, 2003 Millions of dollars, except weighted average settlement price and strike price Natural Gas Derivatives: Expected Maturity in 2003 Expected Maturity in 2004 Expected Maturity in 2005 - ---------------------------- - ---------------------------- ----------- ---------- --------------------- ---------- ---------- ------------ ------------ -------- Settlement Contract Fair Settlement Contract Fair Settlement Contract Fair Price (a) Amount Value Price (a) Amount Value Price (a) Amount Value Futures Contracts: Long($) 5.56 11.3 11.5 5.50 8.3 8.6 4.86 2.8 3.2 Short($) 5.62 1.4 1.3 - - - - - - Strike Contract Price Amount (a) Options: Purchased call (long)($) 5.46 3.5 Purchased put (short) ($) 5.40 9.5 - ---------------------------- ----------- ---------- ------------------------ ------------ ---------------------------------------- - ---------------------------------------------------------------------------------------------------------------------------------- (a) Weighted average
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 of Notes to Condensed Consolidated Financial Statements. The NYMEX futures information above includes those financial positions of both Energy Marketing and SCPC. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. The offset to the change in fair value of these derivatives is recorded as a current asset or liability. Beginning in January 2003, PSNC Energy initiated a hedging program for gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy will include the offset to the change in fair value of derivatives acquired as part of its hedging program in deferred accounts for the over or under recovery of gas costs. PSNC Energy will seek approval of this accounting and cost recovery treatment from the North Carolina Utilities Commission (NCUC) during the annual review of its gas purchasing practices in August 2003. The offset to the change in fair value of these derivatives will be recorded as a regulatory asset or liability. Equity price risk - Investments in telecommunications companies' equity securities (excluding preferred stock with significant debt characteristics) are carried at market value or, if market value is not readily determinable, at cost. The carrying value of the Company's investments in such securities totaled $89.8 million at June 30, 2003. A temporary decline in value of ten percent would result in a $9.0 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 (Loss). An other than temporary decline in value of ten percent would result in a $9.0 million reduction in fair value and a corresponding adjustment to net income, net of tax effect. Item 4. Controls and Procedures As of June 30, 2003 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of June 30, 2003 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended June 30, 2003 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting. SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION
Item 1. Financial Statements SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - ----------------------------------------------------------------------------- ----------------------- June 30, December 31, Millions of dollars 2003 2002 - ----------------------------------------------------------------------------- ----------------------- Assets Utility Plant: Electric $5,066 $4,934 Gas 445 439 Other 197 184 - ----------------------------------------------------------------------------- ----------------------- Total 5,708 5,557 Accumulated depreciation and amortization (1,991) (1,912) - ----------------------------------------------------------------------------- ----------------------- Total 3,717 3,645 Construction work in progress 795 604 Nuclear fuel, net of accumulated amortization 28 38 - ----------------------------------------------------------------------------- ----------------------- Utility Plant, Net 4,540 4,287 - ----------------------------------------------------------------------------- ----------------------- Nonutility Property and Investments, Net 26 25 - ----------------------------------------------------------------------------- ----------------------- - ----------------------------------------------------------------------------- ----------------------- Current Assets: Cash and temporary investments 81 56 Receivables, net 226 237 Receivables - affiliated companies 64 46 Inventories (at average cost): Fuel 32 48 Materials and supplies 50 53 Emission allowances 9 10 Prepayments 27 24 - ----------------------------------------------------------------------------- ----------------------- Total Current Assets 489 474 - ----------------------------------------------------------------------------- ----------------------- Deferred Debits: Environmental 12 18 Nuclear plant decommissioning - 87 Assets held in trust, net - nuclear decommissioning 36 - Pension asset, net 266 265 Due from affiliates - pension and postretirement benefits 19 18 Other regulatory assets 295 267 Other 124 111 - ----------------------------------------------------------------------------- ----------------------- Total Deferred Debits 752 766 - ----------------------------------------------------------------------------- ----------------------- Total $5,807 $5,552 ============================================================================= =======================
- --------------------------------------------------------------------------------- ----------------- -------------------- June 30, December 31, Millions of dollars 2003 2002 - --------------------------------------------------------------------------------- ----------------- -------------------- Capitalization and Liabilities Stockholders' Investment: Common equity $1,977 $1,966 Preferred stock (Not subject to purchase or sinking funds) 106 106 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Stockholders' Investment 2,083 2,072 Preferred Stock, net (Subject to purchase or sinking funds) 9 9 Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G - 50 Long-Term Debt, net 1,774 1,534 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Capitalization 3,866 3,665 - --------------------------------------------------------------------------------- ----------------- -------------------- Current Liabilities: Short-term borrowings 212 178 Current portion of long-term debt 144 144 Accounts payable 87 124 Accounts payable - affiliated companies 83 77 Customer deposits 24 22 Taxes accrued 109 93 Interest accrued 37 31 Dividends declared 38 42 Deferred income taxes, net 2 12 Other 25 37 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Current Liabilities 761 760 - --------------------------------------------------------------------------------- ----------------- -------------------- Deferred Credits: Deferred income taxes, net 616 610 Deferred investment tax credits 107 108 Reserve for nuclear plant decommissioning - 87 Asset retirement obligation - nuclear plant 114 - Due to affiliates - pension and postretirement benefits 16 17 Postretirement benefits 136 131 Regulatory liabilities 124 109 Other 67 65 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Deferred Credits 1,180 1,127 - --------------------------------------------------------------------------------- ----------------- -------------------- Total $5,807 $5,552 ================================================================================= ================= ==================== See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - ---------------------------------------------------------------- -------------------------- ------------------------- Three Months Ended Six Months Ended June 30, June 30, Millions of dollars 2003 2002 2003 2002 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Operating Revenues: Electric $358 $350 $695 $654 Gas 64 53 204 160 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Total Operating Revenues 422 403 899 814 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Operating Expenses: Fuel used in electric generation 71 75 140 131 Purchased power (including affiliated purchases) 34 42 65 75 Gas purchased for resale 50 40 150 112 Other operation and maintenance 100 97 202 180 Depreciation and amortization 48 42 95 84 Other taxes 31 28 61 54 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Total Operating Expenses 334 324 713 636 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Operating Income 88 79 186 178 Other Income, Including Allowance for Equity Funds Used During Construction of $4, $6, $8 and $11 8 10 15 19 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Income Before Interest Charges, Income Taxes and Preferred Stock Dividends 96 89 201 197 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $2, $3, $4 and $7 34 29 66 57 Dividend Requirement of Company - Obligated Mandatorily Redeemable Preferred Securities 1 1 2 2 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Income Before Income Taxes and Preferred Stock Dividends 61 59 133 138 Income Taxes 21 19 46 46 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Net Income 40 40 87 92 Preferred Stock Cash Dividends Declared (At stated rates) 2 2 4 4 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Earnings Available for Common Stockholder $38 $38 $83 $88 ================================================================ ============ ============= ============= =========== See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - -------------------------------------------------------------------------------------------- ---------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 - -------------------------------------------------------------------------------------------- -------------- ------------- Cash Flows From Operating Activities: Net income $87 $92 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 95 84 Amortization of nuclear fuel 12 7 Allowance for funds used during construction (12) (18) Over (under) collections, fuel adjustment clauses 25 (11) Changes in certain assets and liabilities: (Increase) decrease in receivables (7) (36) (Increase) decrease in inventories 20 (6) (Increase) decrease in prepayments (3) (15) (Increase) decrease in pension asset (1) (13) (Increase) decrease in other regulatory assets (18) (1) Increase (decrease) in deferred income taxes, net (4) 11 Increase (decrease) in regulatory liabilities 21 18 Increase (decrease) in postretirement benefits 5 5 Increase (decrease) in accounts payable (31) 5 Increase (decrease) in taxes accrued 16 (59) Increase (decrease) in interest accrued 6 6 Changes in other assets (2) (15) Changes in other liabilities 6 5 - -------------------------------------------------------------------------------------------- ------------- -------------- Net Cash Provided From Operating Activities 215 59 - -------------------------------------------------------------------------------------------- ------------- -------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (304) (238) Proceeds from sales of assets - 1 Increase in nonutility property - (1) Increase in investments (8) (3) - -------------------------------------------------------------------------------------------- ------------- -------------- Net Cash Used For Investing Activities (312) (241) - -------------------------------------------------------------------------------------------- ------------- -------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 495 295 Other long-term debt 2 - Capital contribution from parent - 3 Repayments: Mortgage Bonds (250) (104) Other long-term debt (8) (2) SCE&G Trust I Preferred Securities (50) - Payment of deferred financing costs (21) - Dividends and distributions: Common stock (76) (75) Preferred stock (4) (4) Short-term borrowings, net 34 48 - -------------------------------------------------------------------------------------------- ------------- -------------- Net Cash Provided From Financing Activities 122 161 - -------------------------------------------------------------------------------------------- ------------- -------------- Net Increase (Decrease) In Cash and Temporary Investments 25 (21) Cash and Temporary Investments, January 1 56 37 - -------------------------------------------------------------------------------------------- ------------- -------------- Cash and Temporary Investments, June 30 $81 $16 ============================================================================================ ============= ============== Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $4 and $7) $60 $84 - Income taxes - 45
See Notes to Condensed Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2003 (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, 2002. 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, 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 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 June 30, 2003, approximately $307 million and $124 million of regulatory assets and liabilities, respectively, as shown below. June 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Accumulated deferred income taxes, net $86 $86 Under-collections - fuel adjustment clauses 24 50 Deferred environmental remediation costs 12 18 Asset retirement obligation - nuclear decommissioning 51 - Deferred non-conventional fuel tax benefits, net (52) (40) Storm damage reserve (34) (32) Franchise agreements 64 65 Other 32 29 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Total $183 $176 =============================================================================== Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under-collections - fuel adjustment clauses represent amounts under-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings. Deferred environmental remediation costs represent costs associated with the assessment and clean up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by the Company are being recovered through rates, and such costs, totaling approximately $12 million, are expected to be fully recovered by the end of 2005. Asset retirement obligation - nuclear decommissioning represents the regulatory asset associated with the legal obligation of decommissioning and dismantling V. C. Summer Nuclear Station (Summer Station) as required in SFAS 143, "Accounting for Asset Retirement Obligations." (See Note 1B). Deferred non-conventional fuel tax benefits represent the deferral of partnership losses and other expenses, offset by the accumulated deferred income tax credits associated with two of the Company's partnerships involved in converting coal to alternate fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced and consumed by the Company and ultimately passed through to the Company, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a ten-year period. The accumulated storm damage reserve can be applied to offset actual storm damage costs in excess of $2.5 million in a calendar year. Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are not earning a return, but are being amortized through cost of service over the next 15 years. The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to SCPSC approval. 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 adversely affected. B. New Accounting Standards The Company adopted SFAS 143 effective January 1, 2003. SFAS 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. As of December 31, 2002, prior to the adoption of SFAS 143, the Company carried deferred debits and deferred credits each totaling approximately $87 million related to the decommissioning and dismantling of Summer Station and the funding thereof. Effective January 1, 2003, in connection with the measurement of the ARO upon the adoption of SFAS 143, the amounts reflected within these regulatory assets and liabilities were recharacterized. The following table presents such recharacterized amounts related to the decommissioning obligation and the funding thereof as recorded in the condensed consolidated balance sheet as of June 30, 2003, and the pro forma amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been adopted at the beginning of 2001. As of June 30, December 31, December 31, Millions of dollars 2003 2002 2001 - ------------------- Actual Proforma Proforma Assets: Within electric plant $40 $40 $40 Within accumulated depreciation (13) (13) (12) Assets held in trust (net) - nuclear decommissioning 36 39 35 Within other regulatory assets 51 45 42 ------------- ---------------- ------- ------------- ---------------- ------- Total $114 $111 $105 ============= ================ ======= ============= ================ ======= Liabilities: Asset retirement obligation - nuclear plant decommissioning $114 $111 $105 ============ ============== =========== Proforma net income (loss) for periods prior to the adoption of SFAS 143 would not differ from amounts actually recorded during these periods. In addition to the ARO for Summer Station, the Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated. The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145. The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150. C. Affiliated Transactions The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The company purchases all of its natural gas requirements from South Carolina Pipeline Corporation (SCPC). The Company had approximately $18.3 million and $29.6 million payable to SCPC for such gas purchases at June 30, 2003 and December 31, 2002, respectively. The Company purchases all of the electric generation of Williams Station, which is owned by South Carolina Generating Company (GENCO), under a unit power sales agreement. The Company had approximately $8.5 million and $9.0 million, payable to GENCO for unit power purchases at June 30, 2003 and December 31, 2002, respectively. Such unit power purchases, which are included in "Purchased power", amounted to approximately $20.9 million and $39.2 million for the three and six months ended June 30, 2003, respectively, and $27.9 million and $53.7 million for the three and six months ended June 30, 2002, respectively. The Company holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. The Company had recorded as receivables from affiliated companies for these investments approximately $15.5 million and $8.5 million at June 30, 2003 and December 31, 2002, respectively. The Company had recorded as payables to affiliated companies for these investments approximately $13.2 million and $8.0 million at June 30, 2003 and December 31, 2002, respectively. D. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003. 2. RATE AND OTHER REGULATORY MATTERS Electric In January 2003 the SCPSC issued an order granting the Company an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for the Company's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, the Company may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. In May 2002 the SCPSC issued an order approving the Company's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for 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 2002. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending. In January 2003, in conjunction with the approval of the above retail rate increase, the SCPSC approved the Company's request to reduce the fuel component to 1.678 cents per KWh. This reduction was effective for service rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order approving the Company's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of the Company's purchasing practices and recognized the efficiency of the Company's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the above appeal to the Circuit Court of the SCPSC's May 2002 order. Gas The Company's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by the Company. The Company's cost of gas component in effect during the period January 1, 2002 through June 30, 2003 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.728 January-February 2003 $.596 January-October 2002 $.928 March-June 2003 $.728 November-December 2002 The SCPSC allows the Company 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 recorded in deferred debits. In October 2002, as a result of the annual review, the SCPSC reaffirmed the Company's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at June 30, 2003 of $12.3 million. 3. LONG-TERM DEBT On January 23, 2003 the Company issued $200 million of First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. On May 21, 2003 the Company issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. The Company used the net proceeds from the sale of these bonds and certain other Company funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. In anticipation of the issuance of debt, the Company uses interest rate lock agreements to manage interest rate risk. Payments received or made upon termination of interest rate lock agreements are recorded within other deferred debits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreeement. 4. RETAINED EARNINGS The Company's Restated Articles of Incorporation 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 June 30, 2003 approximately $42.4 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock. 5. COMMITMENTS AND CONTINGENCIES Reference is made to Note 11 of Notes to Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. Commitments and Contingencies at June 30, 2003 include the following: A. Lake Murray Dam Reinforcement In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that the Company reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through June 30, 2003 totaled approximately $105 million. 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 Summer Station, would be approximately $58.7 million per incident, but not more than $6.7 million per year. The Price-Anderson Indemnification Act expired in August 2002, but is expected to renew with only modest changes in 2003. This has no impact on the Company at present due to the "grandfathered" status of existing licensees that are covered under the past act until such time as it is renewed. The Company currently maintains policies (for itself and on behalf of Santee Cooper) 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 $15.8 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 would 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 solely to regulated operations. At the Company, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $8.2 million at June 30, 2003. The deferral includes the estimated costs associated with the following matters. The Company owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of June 30, 2003, the Company has spent approximately $18.7 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.2 million. The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. In addition, in March 2003 the Company signed a consent agreement with DHEC related to a site formerly owned by the Company. The site contained residue material that was moved from the Columbia MGP. The removal action for this site has been completed. The Company is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. The Company anticipates that major remediation activities for the three owned sites will be completed before 2006. The Company has spent approximately $2.3 million related to all of these sites, and expects to spend an additional $5.7 million. 6. 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 and Gas Distribution segments. Accumulated depreciation is not assignable to Electric Operations and Gas Distribution segments; therefore, it is reflected as an adjustment to arrive at consolidated total assets. Intersegment revenues were not significant.
Disclosure of Reportable Segments (Millions of Dollars) Three months ended June 30, 2003 2002 - ------------------------------- ---------------------------------------- ---------------------------------------- - ------------------------------- ----------- ---------------- ----------- External Operating Segment External Operating Segment Revenue Income (Loss) Assets Revenue Income (Loss) Assets - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ ------------ -------------- ------------ Electric Operations $358 $93 $5,865 $350 $83 $5,306 Gas Distribution 64 (5) 454 53 (4) 435 All Other - - - - - 4 Adjustments/Eliminations - - (512) - - (541) - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ Consolidated Total $422 $88 $5,807 $403 $79 $5,204 =============================== =========== ================ =========== ============ ============== ============ Six months ended June 30, 2003 2002 - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ External Operating Segment External Operating Segment Revenue Income Assets Revenue Income (Loss) Assets - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ Electric Operations $695 $174 $5,865 $654 $167 $5,306 Gas Distribution 204 12 454 160 12 435 All Other - - - - - 4 Adjustments/Eliminations - - (512) - (1) (541) - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ - ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------ Consolidated Total $899 $186 $5,807 $814 $178 $5,204 =============================== =========== ================ =========== ============ ============== ============
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, 2002. 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) performance of SCANA Corporation's pension plan assets and the impact on SCE&G's results of operations, (10) inflation, (11) changes in environmental regulations and (12) the other risks and uncertainties described from time to time in SCE&G's periodic reports filed with the United States Securities and Exchange Commission (SEC). SCE&G disclaims any obligation to update any forward-looking statements. COMPETITION Electric Operations In South Carolina electric restructuring efforts remain stalled, and the state legislature adjourned for the year without considering electric restructuring legislation. At the federal level, energy legislation passed both houses of Congress in 2003, though significant differences exist between the House and Senate versions. Some of the more stringent provisions of this legislation, either currently included or expected to be debated in conference committee, would require that one percent of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent by 2020, be generated from renewable energy resources. Renewable energy resources, as defined in the legislation, may exclude hydroelectric generation. Substantial penalties would be levied for failure to comply. Electric cooperatives and municipal utilities would be exempt from these requirements. SCE&G cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities. In July 2002 the United States Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and will attempt, in large measure, to standardize the national energy market. If implemented, the proposed rule may have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. On April 28, 2003 FERC issued a "white paper" regarding SMD which describes how the final SMD rule will differ from the NOPR. SCE&G is currently evaluating FERC's actions to determine potential effects on SCE&G's operations. Additional directives from FERC are expected. Gas Distribution Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact SCE&G's ability to retain large commercial and industrial customers on a monthly basis. LIQUIDITY AND CAPITAL RESOURCES SCE&G's cash requirements arise primarily from its operational needs, funding its construction program and payment of dividends to SCANA. The ability of SCE&G to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. SCE&G's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief, if requested. In January 2003 the Public Service Commission of South Carolina (SCPSC) issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the six months ended June 30, 2003 and 2002:
- ------------------------------------------------------------------------------------ ---------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------------ --------------- ------------ Net cash provided from operating activities $215 $59 Net cash provided from financing activities 122 161 Funds used for investments (8) (3) Cash and temporary cash investments available at the beginning of the period 56 37 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $(304) $(238)
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 June 30, 2003 was 3.33. CAPITAL TRANSACTIONS On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds having an annual interest rate of 5.80% and maturing January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net proceeds from the sale of these bonds and certain other SCE&G funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. CAPITAL PROJECTS In May 2002 SCE&G began construction of 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. The $450 million facility is expected to begin commercial operation in mid-2004, and SCG Pipeline, Inc., an affiliate, will transport natural gas to the facility. In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through June 30, 2003 totaled approximately $105 million. In 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the above Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the initial borrowing. At June 30, 2003 SCE&G has not yet borrowed under the agreement. Environmental Matters For information on environmental matters see Note 5C of Notes To Condensed Consolidated Financial Statements. Other Matters Nuclear Station License Extension In August 2002 SCE&G filed an application with the Nuclear Regulatory Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). If approved, the extension would allow the plant to operate through 2042. At June 30, 2003 SCE&G had capitalized approximately $9 million related to the application process and expects to capitalize an additional $3 million. SCE&G expects the extension to be granted in mid-2004. Off-Balance Sheet Arrangement During the formation of South Carolina Generating Company, Inc. (GENCO) (a wholly owned subsidiary of SCANA) in 1994, SCE&G's $36 million Berkeley County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition, holders of Berkeley Bonds may have recourse against SCE&G in the event of default by GENCO. Synthetic Fuel SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of June 30, 2003 is approximately $4 million, and through June 30, 2003, they have generated and passed through to SCE&G approximately $74 million in such tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through SCE&G from synfuel produced and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A of Notes to Consolidated Financial Statements. On June 27, 2003 the Internal Revenue Service (IRS) announced that it is reviewing the scientific validity of certain test procedures and results that have been presented by other taxpayers as evidence that solid coal-based synthetic fuels have undergone a significant chemical change. Pending completion of this review, the IRS has suspended the issuance of Private Letter Rulings on the question of significant chemical change for requests that rely on the testing procedures and results being reviewed. After the IRS concludes its review, which may occur before the end of 2003, the IRS may seek to disallow synfuel tax credits retroactively, prospectively or both. Although one of the partnerships in which the Company owns an interest is currently under audit by the IRS, there have been no issues raised with respect to the validity of synthetic fuel tax credits. While the Company is not able to determine what conclusion the IRS will reach, to the extent the IRS disallows synfuel tax credits, there would not be a material adverse effect on the Company's financial position, results of operations or cash flows. RESULTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2003 AS COMPARED TO THE CORRESPONDING PERIODS IN 2002 Net Income Net income for the second quarter and year to date periods ended June 30, 2003 and 2002 was as follows:
- ----------------------------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - -------------------------------- ---------- ------------------------------ -------- ----------------- --------- ---------- ---------- --------- Net income $39.9 $39.4 $0.5 1.3% $87.0 $91.4 $(4.4) (4.8%) - -------------------------------- ---------- ---------- ------------------- -------- ------- ---------
Second Quarter 2003 vs 2002 Net income increased slightly due to higher electric margins of $20.8 million and higher gas margins of $0.4 million which were partially offset by higher operation and maintenance expense of $4.0 million, higher depreciation expense of $5.1 million, higher interest expense of $4.9 million, higher property taxes of $2.6 million and lower equity AFC of $1.6 million. Year to Date 2003 vs 2002 Net income decreased primarily due to higher operation and maintenance expense of $22.1 million, higher depreciation expense of $10.9 million, higher interest expense of $9.0 million, higher property taxes of $5.1 million and lower equity AFC of $3.5 million, which were partially offset by higher electric margins of $41.8 million and higher gas margins of $5.9 million. Pension Income For the last several years, the market value of SCE&G's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income for 2003 decreased significantly compared to corresponding periods in 2002 primarily as a result of declines in the value of investments through 2002. Pension income during these periods was recorded on SCE&G's financial statements as follows:
- --------------------------------------------------------------------------- ------------------- Second Quarter Year to Date Millions of dollars 2003 2002 2003 2002 - ---------------------------------------------------------------- ---------- ---------- --------- - ---------------------------------------------------------------- ---------- ---------- --------- Income Statement Impact: (Increase) Decrease in employee benefit costs $(0.8) $3.1 $(1.4) $6.5 Increase in other income 1.9 1.8 3.9 3.9 Balance Sheet Impact: (Increase) Decrease in capital expenditures (0.2) 1.0 (0.4) 1.9 (Increase) Decrease in amount due to Summer Station co-owner (0.1) 0.3 (0.1) 0.6 - ---------------------------------------------------------------- ---------- ---------- --------- - ---------------------------------------------------------------- ---------- ---------- --------- Total Pension Income $0.8 $6.2 $2.0 $12.9 ================================================================ ========== ========== =========
Allowance for Funds Used During Construction (AFC) AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. The decrease in AFC for the three and six months ended June 30, 2003 is primarily the result of the completion of the Urquhart Station repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased construction expenditures related to the Jasper County Generating Station project in 2003 and the Lake Murray Dam project (see discussion at CAPITAL PROJECTS). Dividends Declared SCE&G's Board of Directors has declared the following dividends on common stock held by SCANA during 2003: ------------------- ----------------- --------------------- ----------------- Declaration Date Amount Quarter Ended Payment Date ------------------- ----------------- --------------------- ----------------- February 20, 2003 $35.3 million March 31, 2003 April 1, 2003 May 1, 2003 $36.5 million June 30, 2003 July 1, 2003 July 31, 2003 $37.0 million September 30, 2003 October 31, 2003 ----------------------- ----------------- --------------------- ------------- Electric Operations Electric Operations is comprised of the electric portion of SCE&G and South Carolina Fuel Company, Inc. Changes in the electric operations sales margins were as follows:
---------------------------------- -------------------------------------- ----------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ---------------------------------- --------- --------- ------------------ ---------- ---------- ------------------- ---------------------------------- --------- --------- ------- ---------- ---------- ---------- -------- ---------- Operating Revenues $357.8 $349.6 $8.2 2.3% $695.2 $653.9 $41.3 6.3% Less: Fuel used in generation 70.8 75.2 (4.4) (5.9%) 139.9 130.7 9.2 7.0% Purchased power 33.9 42.1 (8.2) (19.5%) 65.3 75.0 (9.7) (12.9%) ---------------------------------- --------- --------- ------- ---------- ---------- ---------- -------- ---------- ---------------------------------- --------- --------- ------- ---------- ---------- ---------- -------- ---------- Margin $253.1 $232.3 $20.8 9.0% $490.0 $448.2 $41.8 9.3% ================================== ========= ========= ======= ========== ========== ========== ======== ==========
Second Quarter 2003 vs 2002 Margin increased by $20.4 million due to the increase in retail electric base rates approved in January 2003 and by customer growth of $7.4 million partially offset by less favorable weather of $7.9 million. Fuel used in generation and purchased power decreased due to milder weather that resulted in a 1.6% decline in total kilowatt-hour sales. Year to Date 2003 vs 2002 Margin increased by $30.1 million due to the increase in retail electric base rates approved in January 2003 and by $13.8 million due to customer growth and increased consumption partially offset by the effects of less favorable weather of $2.3 million. Fuel used in generation increased and purchased power decreased due to a planned outage at GENCO. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Changes in the gas distribution sales margins were as follows:
---------------------------------- --------------------------------------- ---------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ---------------------------------- --------- --------- ------------------- --------- ---------- ------------------- ---------------------------------- --------- --------- --------- --------- --------- ---------- -------- ---------- Operating Revenues $63.9 $53.0 $10.9 20.6% $204.0 $160.1 $43.9 27.4% Less: Gas purchased for resale 50.1 39.6 10.5 26.5% 150.3 112.3 38.0 33.8% ---------------------------------- --------- --------- --------- -------- --------- --------- ---------- Margin $13.8 $13.4 $0.4 3.0% $53.7 $47.8 $5.9 12.3% ================================== ========= ========= ========= ========= ========= ========== ======== ==========
Second Quarter 2003 vs 2002 Margin increased primarily due to increased recovery of environmental remediation expenses (offset in operations and maintenance) of $0.3 million and customer growth and increased consumption of $1.3 million, partially offset by a decrease in industrial usage of $1.2 million due to an unfavorable competitive position of natural gas relative to alternate fuels. Year to Date 2003 vs 2002 Margin increased primarily due to customer growth and increased consumption of $1.3 million and recovery of environmental remediation expenses of $1.6 million (offset in operations and maintenance), partially offset by a decrease in industrial usage of $1.4 million due to an unfavorable competitive position of natural gas relative to alternate fuels.
Other Operating Expenses Changes in other operating expenses were as follows: ------------------------------------- -------------------------------------- ----------------------------------------- Second Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ------------------------------------- ---------- --------- ----------------- --------- ---------- -------------------- Other operation and maintenance $100.8 $96.8 $4.0 4.1% $201.7 $179.6 $22.1 12.3% Depreciation and amortization 47.6 42.5 5.1 12.0% 94.9 84.0 10.9 13.0% Other taxes 30.7 27.8 2.9 10.4% 60.6 54.3 6.3 11.6% ------------------------------------- ---------- --------- ------- --------- --------- ---------- --------- ---------- ------------------------------------- ---------- --------- ------- --------- --------- ---------- --------- ---------- Total $179.1 $167.1 $12.0 7.2% $357.2 $317.9 $39.3 12.4% ===================================== ========== ========= ======= ========= ========= ========== ========= ==========
Second Quarter 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $3.9 million and increased labor and benefit costs of $1.1 million. Depreciation and amortization expense increased by $3.5 million due to normal net property additions and by $1.6 million due to the completion of the Urquhart Station repowering project in June 2002. Other taxes increased primarily due to increased property taxes. Year to Date 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $7.9 million, increased labor and benefits costs of $4.0 million, increased healthcare cost of $4.2 million, increased environmental remediation costs of $1.6 million and increased other operating expenses for electric generation and transmission of $2.5 million. Depreciation and amortization expense increased by $6.7 million due to normal net property additions and by $4.2 million due to the completion of the Urquhart Station repowering project in June 2002. Other taxes increased primarily due to increased property taxes. Other Income Other income for second quarter and year to date 2003 vs 2002, including AFC, decreased primarily due to completion of the Urquhart Station Repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating Project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by the Jasper County Generation Station project and Lake Murray Dam Project. Interest Expense Second Quarter 2003 vs 2002 Interest expense increased by $6.2 million due to increased long-term debt and by $1.3 million due to lower AFC. These increases were partially offset by $2.4 million due to lower interest rates. Year to Date 2003 vs 2002 Interest expense increased by $10.9 million due to increased long-term debt and by $2.8 million due to lower AFC. These increases were partially offset by $4.9 million due to lower interest rates. Income Taxes Income taxes changed primarily as a result of changes in operating income. Item 3. Quantitative and Qualitative Disclosures About Market Risk All financial instruments held by SCE&G and described below are held for purposes other than trading. Interest rate risk - The table below provides information about long-term debt issued by SCE&G which is sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. Fair values for debt represent quoted market prices.
As of June 30, 2003 Millions of dollars Expected Maturity Date There- Fair Liabilities 2003 2004 2005 2006 2007 after Total Value - ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- -------------- - ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- -------------- Long-Term Debt: Fixed Rate ($) 145.8 138.4 188.4 169.1 38.2 1,430.6 2,110.5 2,086.1 Average Interest Rate (%) 6.29 7.44 7.35 8.49 6.74 6.22 6.60
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. Item 4. Controls and Procedures As of June 30, 2003 an evaluation was performed under the supervision and with the participation of SCE&G's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that as of June 30, 2003 SCE&G's disclosure controls and procedures were effective. There has been no change in SCE&G's internal conrol over financial reporting during the quarter ended June 30, 2003 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED FINANCIAL SECTION 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).
PART I. FINANCIAL INFORMATION Item 1. Financial Statements. -------------------- PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - ------------------------------------------------------------------------ ------------------- June 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------ ------------------- Assets Gas Utility Plant $918 $895 Accumulated depreciation (336) (318) Acquisition adjustment, net of accumulated amortization 210 210 - ------------------------------------------------------------------------ ------------------- Gas Utility Plant, Net 792 787 - ------------------------------------------------------------------------ ------------------- Nonutility Property and Investments, Net 27 28 - ------------------------------------------------------------------------ ------------------- Current Assets: Cash and temporary investments 4 1 Restricted cash and temporary investments 7 7 Receivables, net of allowance for uncollectible accounts of $2 and $2 48 98 Receivables-affiliated companies 13 14 Inventories (at average cost): Stored gas 37 38 Materials and supplies 5 6 Prepayments 1 1 Deferred income taxes, net 3 3 - ------------------------------------------------------------------------ ------------------- Total Current Assets 118 168 - ------------------------------------------------------------------------ ------------------- Deferred Debits: Due from affiliate-pension asset 14 14 Regulatory assets 32 20 Other 6 7 - ------------------------------------------------------------------------ ------------------- Total Deferred Debits 52 41 - ------------------------------------------------------------------------ ------------------- Total $989 $1,024 ======================================================================== =================== ======================================================================== =================== Capitalization and Liabilities Capitalization: Common equity 503 $487 Long-term debt, net 283 286 - ------------------------------------------------------------------------ ------------------- Total Capitalization 786 773 - ------------------------------------------------------------------------ ------------------- Current Liabilities: Short-term borrowings - 31 Current portion of long-term debt 8 8 Accounts payable 28 44 Accounts payable-affiliated companies 8 7 Customer prepayments and deposits 7 12 Taxes accrued 2 5 Interest accrued 5 6 Distributions/Dividends declared 5 5 Other 10 11 - ------------------------------------------------------------------------ ------------------- Total Current Liabilities 73 129 - ------------------------------------------------------------------------ ------------------- Deferred Credits: Deferred income taxes, net 92 91 Deferred investment tax credits 2 2 Due to affiliate-postretirement benefits 16 16 Regulatory liabilities 9 1 Other 11 12 - ------------------------------------------------------------------------ ------------------- Total Deferred Credits 130 122 - ------------------------------------------------------------------------ ------------------- Total $989 $1,024 ======================================================================== =================== See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - ----------------------------------------------------------------------------- ------------------------- ------------------------- Three Months Ended Six Months Ended June 30, June 30, Millions of dollars 2003 2002 2003 2002 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Operating Revenues $82 $49 $284 $183 Cost of Gas 52 21 183 88 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Gross Margin 30 28 101 95 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Operating Expenses: Operation and maintenance 19 16 37 34 Depreciation 9 9 17 17 Other taxes 2 2 4 4 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Total Operating Expenses 30 27 58 55 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Operating Income - 1 43 40 Other Income, Including Allowance for Equity Funds Used During Construction 2 1 4 2 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction 5 5 10 11 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Income (Loss) Before Income Tax Expense (Benefit) and Cumulative Effect of Accounting Change (3) (3) 37 31 Income Tax Expense (Benefit) (1) (1) 14 12 - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Income (Loss) Before Cumulative Effect of Accounting Change (2) (2) 23 19 Cumulative Effect of Accounting Change, Net of Taxes - - - (230) - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ - ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------ Net Income (Loss) $(2) $(2) $23 $(211) ============================================================================= ============ ============ ============ ============ See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - ---------------------------------------------------------------------------------------------- ----------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 - ---------------------------------------------------------------------------------------------- --------------- ------------- Cash Flows From Operating Activities: Net income (loss) $23 $(211) Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - 230 Depreciation 18 19 Allowance for funds used during construction (1) - Over (under) collection, gas cost adjustment clause (4) (15) Changes in certain assets and liabilities: (Increase) decrease in receivables, net 51 43 (Increase) decrease in inventories 2 13 Increase (decrease) in accounts payable and advances (15) (26) Increase (decrease) in deferred income taxes, net 1 1 Increase (decrease) in taxes accrued (3) (4) Changes in other assets 2 1 Changes in other liabilities (6) 3 - ---------------------------------------------------------------------------------------------- --------------- ------------- Net Cash Provided From Operating Activities 68 54 - ---------------------------------------------------------------------------------------------- --------------- ------------- Cash Flows From Investing Activities: Construction expenditures (22) (24) Nonutility and other (1) - - ---------------------------------------------------------------------------------------------- --------------- ------------- Net Cash Used For Investing Activities ( 23) (24) - ---------------------------------------------------------------------------------------------- --------------- ------------- Cash Flows From Financing Activities: Repayment of short-term borrowings, net (31) - Capital contributions from parent 2 1 Retirement of long-term debt (3) - Distributions/Dividend payments (10) (5) - ---------------------------------------------------------------------------------------------- --------------- ------------- Net Cash Used For Financing Activities (42) (4) - ---------------------------------------------------------------------------------------------- --------------- ------------- Net Increase In Cash and Temporary Investments 3 26 Cash and Temporary Investments, January 1 1 18 - ---------------------------------------------------------------------------------------------- --------------- ------------- Cash and Temporary Investments, June 30 $4 $44 ============================================================================================== =============== ============= Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $0.6 and $0.5) $9 $9 - Income taxes 17 16 See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - ------------------------------------------------------------------- -------------------------- ------------------------ Three Months Ended Six Months Ended June 30, June 30, Millions of dollars 2003 2002 2003 2002 - ------------------------------------------------------------------- ------------- ------------ ----------- ------------ - ------------------------------------------------------------------- ------------- ------------ ----------- ------------ Net Income (Loss) $(2) $(2) $23 $(211) Other Comprehensive Income (Loss), net of tax: Unrealized gains (losses) on hedging activities - - - - - ------------------------------------------------------------------- ------------- ------------ ----------- ------------ - ------------------------------------------------------------------- ------------- ------------ ----------- ------------ Total Comprehensive Income (Loss) (1) $(2) $(2) $23 $(211) =================================================================== ============= ============ =========== ============ (1) Accumulated other comprehensive income (loss) of the Company totaled $(1.3) million and $(1.3) million as of June 30, 2003 and December 31, 2002, respectively.
See Notes to Condensed Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2003 (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, 2002. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Operations 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, 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 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 June 30, 2003 approximately $32 million and $9 million of regulatory assets and liabilities, respectively, as shown below. June 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Excess deferred income taxes $- $(1) Under-collections-gas cost adjustment clause 14 11 Deferred environmental remediation costs 9 9 - ------------------------------------------------------------------------------- Total $23 $19 =============================================================================== Excess deferred income taxes represent deferred income taxes recorded in prior years at a rate higher than the current statutory rate. Pursuant to a North Carolina Utilities Commission (NCUC) order, the Company is required to refund these amounts to customers through a rate decrement. Under-collections-gas cost adjustment clause represents amounts under-collected from customers pursuant to the Company's Rider D mechanism approved by the NCUC. This mechanism allows the Company to recover all prudently incurred gas costs. Deferred environmental remediation costs represents costs associated with the assessment and cleanup of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Management believes that all MGP cleanup costs will be recoverable through gas rates. A portion of the costs incurred are being recovered through rates, and management believes the remaining costs of approximately $7.6 million will be recoverable in the future. Amounts incurred to date that have not been recovered through gas rates are approximately $1.3 million. (See Note 5.) The NCUC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the NCUC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to NCUC approval. 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 adversely affected. B. New Accounting Standards The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. In connection with this implementation, the Company performed a valuation analysis of its acquisition adjustment using an independent appraisal. The analysis indicated that the carrying amount of the acquisition adjustment exceeded its fair value by approximately $230 million. The resulting impairment charge is reflected on the Condensed Consolidated Statement of Operations as the cumulative effect of an accounting change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. The Company performed an annual evaluation as of January 1, 2003 and no further impairment was indicated. The Company adopted SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. SFAS 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. The Company believes that any ARO related to the Company's property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated. The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145. The Company adopted SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS 149 is not expected to have a material impact on the Company's results of operations, cash flows or financial position. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150. C. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003. 2. ACCOUNTING CHANGE As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to the acquisition adjustment which had been recorded in connection with its acquisition by SCANA Corporation. The charge is reflected on the Condensed Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1B. 3. RATE AND OTHER REGULATORY MATTERS The Company's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. The Company revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews the Company's gas purchasing practices annually. The Company's benchmark cost of gas in effect during the period January 1, 2002 through June 30, 2003 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.460 January-February 2003 $.300 January 2002 $.595 March 2003 $.215 February-June 2002 $.725 April-June 2003 $.350 July-October 2002 $.410 November-December 2002 On April 24, 2003 the NCUC issued an order in the Company's 2002 Annual Prudence Review. The NCUC determined that the Company's gas costs during the 12-month review period ended March 31, 2002 were reasonable and prudently incurred. The NCUC also authorized new temporary rate decrements to refund certain balances in deferred accounts. On June 2, 2003 the Company filed testimony in the 2003 Annual Prudence Review related to the 12 months ended March 31, 2003. The NCUC will hold a hearing on August 12, 2003 to review the Company's filing. A state expansion fund, established by the North Carolina General Assembly 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. In June 2000 the NCUC approved the Company's requests for disbursement of up to $28.4 million from the Company's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. The Company estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion is expected to be completed in the spring of 2004. Through June 30, 2003 approximately $20 million had been spent on this project. In December 1999 the NCUC issued an order approving SCANA's acquisition of the Company. As specified in the order, the Company 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 material adverse governmental actions and force majeure events. 4. FINANCIAL INSTRUMENTS SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, 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 fair value of the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties. On January 2, 2003 the Company filed a summary of its hedging program for natural gas purchases with the NCUC for informational purposes. The primary goal of the program is to reduce price volatility to firm customers. The program and any related transactions will be addressed in the August 2003 Annual Prudence Review with the NCUC. Transaction fees and any gains or losses are recorded in deferred accounts for subsequent rate consideration. As of June 30, 2003 the Company had deferred a net gain of approximately $625 thousand. The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable rate and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. Payments received upon termination of a swap are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. The fair value of interest rate swaps is recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. At June 30, 2003 the estimated fair value of the Company's swaps totaled $3.3 million related to combined notional amounts of $37.4 million. 5. COMMITMENTS AND CONTINGENCIES The Company is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. The Company's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. The Company has recorded a liability and associated regulatory asset of $7.6 million, which reflects the estimated remaining liability at June 30, 2003. Amounts incurred to date that have not been recovered through gas rates are approximately $1.3 million. Management believes that all MGP cleanup costs will be recoverable through gas rates. 6. SEGMENT OF BUSINESS INFORMATION Gas Distribution is the Company's only reportable segment. Gas Distribution uses operating income to measure profitability. Intersegment revenues between Gas Distribution and nonreportable segments were not significant.
Disclosure of Reportable Segments (Millions of dollars) Three Months Ended June 30, 2003 2002 ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- External Operating Segment External Operating Segment Revenue Income Assets Revenue Income Assets ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- Gas Distribution $82 - $977 $49 $1 $1,170 All Other - n/a 28 - n/a 28 Adjustments/Eliminations - - (16) - - 3 ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- Consolidated Total $82 - $989 $49 $1 $1,201 ============================== ============= ================ ============= ============= ============== ============= Six Months Ended June 30, 2003 2002 ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- External Operating Segment External Operating Segment Revenue Income Assets Revenue Income Assets ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- Gas Distribution $284 $43 $977 $183 $40 $1,170 All Other - n/a 28 - n/a 28 Adjustments/Eliminations - - (16) - - 3 ------------------------------ ------------- ---------------- ------------- ------------- -------------- ------------- Consolidated Total $284 $43 $989 $183 $40 $1,201 ============================== ============= ================ ============= ============= ============== =============
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 Energy) Annual Report on Form 10-K for the year ended December 31, 2002. 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 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 PSNC Energy'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 Energy's accounting policies, (8) weather conditions, especially in areas served by PSNC Energy, (9) performance of SCANA Corporation's pension plan assets and the impact on PSNC Energy's results of operations, (10) inflation, (11) changes in environmental regulations and (12) the other risks and uncertainties described from time to time in PSNC Energy's periodic reports filed with the United States Securities and Exchange Commission (SEC). PSNC Energy disclaims any obligation to update any forward-looking statements. Net Income (Loss) and Distributions/Dividends Net income (loss) for the six months ended June 30, 2003 and 2002 was as follows: - ----------------------------------------------------------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 - ---------------------------------------------------------------- ------------ Net income (loss) $22.6 $(210.4) Less: Cumulative effect of accounting change - (229.6) - ---------------------------------------------------------------- ------------ - ---------------------------------------------------------------- ------------ Income before cumulative effect of accounting change $22.6 $19.2 ================================================================ ============ Income before cumulative effect of accounting change increased approximately $3.4 million primarily due to increased margin of $6.8 million and other income of $2.1 million which were partially offset by higher operating expenses of $3.5 million and higher income taxes of $2.4 million. In connection with the implementation of SFAS 142, PSNC Energy performed a valuation analysis of its acquisition adjustment using an independent appraisal. The analysis indicated that the carrying amount of the acquisition adjustment exceeded its fair value by $230 million. As a result, PSNC Energy recorded an impairment charge of $230 million effective January 1, 2002. The charge is presented on the Condensed Consolidated Statements of Operations as the Cumulative Effect of an Accounting Change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. PSNC Energy performed an annual evaluation as of January 1, 2003 and no further impairment was indicated. The nature of PSNC Energy's business is seasonal. The quarters ending June 30 and September 30 are generally PSNC Energy's least profitable quarters due to decreased demand for natural gas related to space heating requirements. PSNC Energy's Board of Directors has authorized the following distributions/dividends on common stock held by SCANA during 2003: - --------------------- ---------------- ---------------------- ------------------ Declaration Date Amount Quarter Ended Payment Date - --------------------- ---------------- ---------------------- ------------------ - --------------------- ---------------- ---------------------- ------------------ February 20, 2003 $4.5 million March 31, 2003 April 1, 2003 May 1, 2003 $4.5 million June 30, 2003 July 1, 2003 July 31, 2003 $4.0 million September 30, 2003 October 1, 2003 - --------------------- ---------------- ---------------------- ------------------ Gas Distribution Gas distribution is comprised of the local distribution operations of PSNC Energy. Changes in the gas distribution sales margins were as follows: ------------------------ ----------------------------------------- Six Months Ended June 30, Millions of dollars 2003 2002 Change ------------------------ --------- -------- ---------------------- ------------------------ ---------- Operating revenues $284.9 $183.4 $101.5 55.3% Less: Cost of gas 183.4 94.7 106.8% 88.7 ------------------------ --------- -------- ----------- Gross margin $101.5 $94.7 $6.8 7.2% ======================== ========= ======== =========== ========== Gas distribution sales margin for the six months ended June 30, 2003 increased primarily due to weather that was 13% colder than in 2002 and due to customer growth of approximately 2.8%. Revenues and cost of gas increased as a result of higher commodity natural gas prices. Operation and Maintenance Expenses Operation and maintenance expenses increased $3.5 million for the six months ended June 30, 2003 compared to the same period in 2002 primarily due to increased labor and benefits costs of $1.3 million, increased outside labor and general business expenses of $0.9 million, increased bad debt expense of $0.6 million and the impact of reduced pension income of $0.6 million. Other Income Other income increased $2.1 million compared to the same period in 2002 primarily due to income from secondary market activities, such as off-system gas sales and pipeline capacity release, and an increase in interest income on amounts under-collected from customers through the operation of the Rider D mechanism. This mechanism allows PSNC Energy to recover all prudently incurred gas costs. Income Taxes Income taxes changed primarily as a result of changes in operating and other income. Capital Expansion Program and Liquidity Matters PSNC Energy's capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy's 2003 construction budget is approximately $46.7 million, compared to actual construction expenditures for 2002 of $47.8 million. PSNC Energy's ratio of earnings to fixed charges for the 12 months ended June 30, 2003 was 2.95. At June 30, 2003 PSNC Energy had no outstanding short-term borrowings and had unused lines of credit of $125 million. Item 4. Controls and Procedures As of June 30, 2003 an evaluation was performed under the supervision and with the participation of PSNC Energy's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of PSNC Energy's disclosure controls and procedures. Based on that evaluation, PSNC Energy's management, including the CEO and CFO, concluded that as of June 30, 2003 PSNC Energy's disclosure controls and procedures were effective. There has been no change in PSNC Energy's internal control over financial reporting during the quarter ended June 30, 2003 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting. PART II. OTHER INFORMATION Item 1. Legal Proceedings The following Legal Proceedings were pending at June 30, 2003. These proceedings affect SCANA Corporation and its subsidiaries (the Company) and, to the extent indicated, they also affect SCE&G or PSNC Energy. Rate and Other Regulatory Matters In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for 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 2002. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending. In April 2003 the SCPSC issued an order approving SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices and recognized the efficiency of SCE&G's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the above appeal to the Circuit Court of the SCPSC's May 2002 order. On January 2, 2003 PSNC Energy filed a summary of its hedging program for natural gas purchases with the NCUC for informational purposes. The primary goal of the program is to reduce price volatility to firm customers. The program and any related transactions will be addressed in the August 2003 Annual Prudence Review with the NCUC. Transaction fees and any gains or losses are recorded in deferred accounts for subsequent rate consideration. On June 2, 2003 PSNC Energy filed testimony in the 2003 Annual Prudence Review related to the 12 months ended March 31, 2003. The NCUC will hold a hearing on August 12, 2003 to review PSNC Energy's filing. Lake Murray Dam Reinforcement In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through June 30, 2003 totaled approximately $105 million. Environmental SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of June 30, 2003, SCE&G has spent approximately $18.7 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.2 million. SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from an MGP site. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. SCE&G has spent approximately $2.3 million related to all of these sites, and expects to spend an additional $5.7 million. PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. PSNC Energy has recorded a liability and associated regulatory asset of $7.6 million, which reflects the estimated remaining liability at June 30, 2003. Amounts incurred to date that have not been recovered through gas rates are approximately $1.3 million. Management believes that all MGP cleanup costs incurred by PSNC Energy will be recoverable through gas rates. Pending or Threatened Litigation In 1999 an unsuccessful bidder for the purchase of propane gas assets of a subsidiary of the Company filed suit against SCANA in South Carolina Circuit Court seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material adverse impact on its results of operations, cash flows or financial position. In 2001 a subsidiary of the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of the supplier and its guarantor to meet contractual obligations related to credit support provisions, the subsidiary terminated the contract. A hearing under the binding arbitration provisions of the contract is scheduled for September 2003. In initial pleadings for the hearing, the supplier has demanded payment of at least $134 million in damages from the subsidiary; conversely, the subsidiary demanded payment of no less than $154 million in damages from the supplier. The Company is confident of the propriety of its actions, and the Company will vigorously pursue its position in the arbitration proceedings. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition. The Company, SCE&G and PSNC Energy are also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. Item 2, 3, and 5 are not applicable. Item 4. Submission of Matters to a Vote of Security-Holders (not applicable for South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated) The Annual Meeting of Shareholders of SCANA Corporation Common Stock (No Par Value) was held on May 1, 2003. The following matters were voted upon at the meeting. 1. To elect four Class III Directors for the terms specified in the Proxy Statement. Number of Voting Number of Shares Total Shares Voting Voting to Shares Nominee For Withhold Authority Voted James A. Bennett 91,305,994 2,798,210 94,104,204 William C. Burkhardt 92,802,195 1,302,009 94,104,204 Lynne M. Miller 92,824,202 1,280,002 94,104,204 Maceo K. Sloan 92,704,078 1,400,126 94,104,204 2. To approve the appointment of Deloitte & Touche LLP as independent accountants for the Corporation. Number of Shares FOR 90,601,340 AGAINST 3,035,804 ABSTAIN 467,060 ------- TOTAL 94,104,204 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 second quarter 2003 were as follows: SCANA Corporation: Date of report: April 25, 2003 Items reported: Items 7 and 9 (Item 12 disclosure) South Carolina Electric & Gas Company: Date of report: April 25, 2003 Items reported: Items 7 and 9 (Item 12 disclosure) Date of report: May 16, 2003 Item reported: Items 5 and 7 Public Service Company of North Carolina, Incorporated: Date of report: April 25, 2003 Item reported: Items 7 and 9 (Item 12 disclosure) SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrants) August 8, 2003 By s/James E. Swan, IV ------------------------------------- James E. Swan, IV Controller (Principal accounting officer)
EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy 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 as of the dates indicated below and filed as exhibits to the Registration Statements or Exchange Act filings as set forth below May 22, 2001 Exhibit 3.02 to Registration No. 333-65460 June 14, 2001 Exhibit 3.04 to Registration No. 333-65460 March 13, 2002 Exhibit 3.06 to Registration No. 333-101449 May 9, 2002 Exhibit 3.07 to Registration No. 333-101449 June 4, 2002 Exhibit 3.08 to Registration No. 333-101449 August 12, 2002 Exhibit 3.09 to Registration No. 333-101449 August 30, 2002 Exhibit 3.05 to Registration No. 333-101449 March 13, 2003 Exhibit 3.05 to Form 10-Q filed March 31, 2003 3.05 X Articles of Amendment of SCE&G dated May 22, 2003 (Filed herewith) 3.06 X Articles of Amendment of SCE&G, dated June 18, 2003 (Filed herewith) 3.07 X Articles of Correction of SCE&G dated June 1, 2001 (Filed as Exhibit 3.03 to Registration Statement No. 333-65460) 3.08 X Articles of Incorporation of PSNC Energy (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 Energy 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 Energy 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) Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy 3.13 X By-Laws of PSNC Energy 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) 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 Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy 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 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 Carolina 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 Indenture dated as of January 1, 1996 between PSNC Energy and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206) 4.10 X X First through Fourth Supplemental Indentures to Indenture referred to in Exhibit 4.09 dated as of the dates indicated below and filed as exhibits to the Registration Statements whose file numbers are set forth below January 1, 1996 Exhibit 4.09 to Registration No. 333-45206 December 15, 1996 Exhibit 4.10 to Registration No. 333-45206 February 10, 2000 Exhibit 4.11 to Registration No. 333-45206 February 12, 2001 Exhibit 4.05 to Registration No. 333-68516 Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy 4.11 X PSNC Energy $150 million medium-term note issued February 16, 2002 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516) *10.01 X SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed herewith) *10.02 X SCANA Supplemental Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001) *10.03 SCANA Key Executive Severance X Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2001) *10.04 X SCANA Supplementary Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001) *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 Request for Action by the SCANA Long-Term Equity Compensation Plan Committee of the Board dated August 1, 2002 (Filed herewith) *10.07 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) *10.08 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) *10.09 X SCANA Corporation Director Compensation and Deferral Plan effective January 1, 2001 (Filed herewith) 10.10 X Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206) 10.11 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) 10.12 X Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206) 10.13 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) 10.14 X Form of Severance Agreement between PSNC Energy and its Executive Officers (Filed as Exhibit 10.05 to Registration Statement No. 333-45206) Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy 10.15 X Service Agreement between PSNC Energy and SCANA Services, Inc., effective April 1, 2000 (Filed as Exhibit 10.06 to Registration Statement No. 333-45206) 10.16 X Service Agreement between SCE&G and SCANA Services, Inc., effective April 1, 2002 (Filed as Exhibit 10.01 to Registration Statement No. 333-101449) 31.1 X Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) 31.2 X Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) 31.3 X Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) 31.4 X Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) 31.5 X Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) 31.6 X Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) 32.1 X Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Filed herewith) 32.2 X Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Filed herewith) 32.3 X Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Filed herewith) 32.4 X Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Filed herewith) 32.5 X Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Filed herewith) 32.6 X Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Filed herewith) * Management Contract or Compensatory Plan or Arrangement
EX-3 3 exh305.txt EXHIBIT 3.05 AMENDMENT OF ARTICLES STATE OF SOUTH CAROLINA SECRETARY OF STATE ARTICLES OF AMENDMENT Pursuant to Section 33-10-106 of the 1976 South Carolina Code, as amended, the undersigned corporation adopts the following Articles of Amendment to its Articles of Incorporation: 1. The name of the corporation is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. On , the corporation adopted the following Amendment(s) of its Articles of Incorporation: NOT APPLICABLE 3. The manner, if not set forth in the amendment, in which any exchange, reclassification, or cancellation of issued shares provided for in the Amendment shall be effected, is as follows: (a) The number of redeemable shares of the corporation reacquired by redemption or purchase is 363 itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 4.60% Series B 363 (b) The aggregate number of issued shares of the corporation after giving effect to such cancellation is 41,617,766, itemized as follows:
Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 " " " " 4.60% 0 " " " " 4.50% 6,797 " " " " 4.60% (Series A) 12,052 " " " " 5.125% 65,000 " " " " 4.60% (Series B) 50,637 " " " " 6% 61,924 " " " " 9.40% 0 " " " ($100 par value) 8.12% 0 " " " " 7.70% 0 " " " " 8.40% 0 " " " ($50 par value) 8.72% 0 " " ($100 par value) 6.52% 1,000,000 Common Stock ($4.50 par value) ------ 40,296,147 ---------- 41,617,766
(c) The amount of the stated capital of the corporation after giving effect to such cancellation is $297,413,611.50. Page 2 (d) The number of shares which the corporation has authority to issue after giving effect to such cancellation is 56,411,619, itemized as follows:
Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 " " " " 4.60% 0 " " " " 4.50% 6,797 " " " " 4.60% (Series A) 12,052 " " " " 5.125% 65,000 " " " " 4.60% (Series B) 50,637 " " " " 6% 61,924 " " " " 9.40% 0 " " " ($100 par value) 8.12% 0 " " " " 7.70% 0 " " " " 8.40% 0 " " " ($50 par value) 8.72% 0 " " " ($100 par value) 6.52% 1,000,000 Serial Preferred Stock ($50 par value) (1 vote) ---- 640,000 Serial Preferred Stock ($100 par value) (1 vote) ---- 1,750,000 Serial Preferred Stock ($25 par value) (1/4 vote) ---- 2,000,000 Serial Preferred Stock ($50 par value) (1/2 vote) ---- 700,000 Common Stock ($4.50 par value) ---- 50,000,000 ---------- 56,411,619
-- 4. (a) |__| Amendment(s) adopted by shareholder action. At the date of adoption of the amendment, the number of outstanding shares of each voting group entitled to vote separately on the Amendment, and the vote of such shares was: Number of Number of Number of Votes Number of Undisputed Voting Outstanding Votes Entitled Represented at Shares Voted Group Shares to be Cast the meeting For Against ----- ------------ --------------------------------- ----------------------- --- (b) |XX| The Amendment(s) was duly adopted by the incorporators or board of directors without shareholder approval pursuant to Sections 33-6-102(d), 33-10-102 and 33-10-105 of the 1976 South Carolina Code, as amended, and shareholder action was not required. 5. Unless a delayed date is specified, the effective date of these Articles of Amendment shall be the date of the acceptance for filing by the Secretary of State (See Section 33-1-230(b)): SOUTH CAROLINA ELECTRIC & GAS COMPANY Date: May 22, 2003 By: s/Lynn M. Williams ------------------------------------ Secretary EX-3 4 exh306.txt EXHIBIT 3.06 AMENDMENT OF ARTICLES Exhibit 3.06 STATE OF SOUTH CAROLINA SECRETARY OF STATE ARTICLES OF AMENDMENT Pursuant to Section 33-10-106 of the 1976 South Carolina Code, as amended, the undersigned corporation adopts the following Articles of Amendment to its Articles of Incorporation: 1. The name of the corporation is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. On , the corporation adopted the following Amendment(s) of its Articles of Incorporation: NOT APPLICABLE 3. The manner, if not set forth in the amendment, in which any exchange, reclassification, or cancellation of issued shares provided for in the Amendment shall be effected, is as follows: (a) The number of redeemable shares of the corporation reacquired by redemption or purchase is 363 itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5.125% 1,000 (b) The aggregate number of issued shares of the corporation after giving effect to such cancellation is 41,616,766, itemized as follows:
Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 " " " " 4.60% 0 " " " " 4.50% 6,797 " " " " 4.60% (Series A) 12,052 " " " " 5.125% 64,000 " " " " 4.60% (Series B) 50,637 " " " " 6% 61,924 " " " " 9.40% 0 " " " ($100 par value) 8.12% 0 " " " " 7.70% 0 " " " " 8.40% 0 " " " ($50 par value) 8.72% 0 " " > ($100 par value) 6.52% 1,000,000 Common Stock ($4.50 par value) ------ 40,296,147 ---------- 41,616,766
(c) The amount of the stated capital of the corporation after giving effect to such cancellation is $297,363,611.50. (d) The number of shares which the corporation has authority to issue after giving effect to such cancellation is 56,410,619, itemized as follows:
Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 " " " " 4.60% 0 " " " " 4.50% 6,797 " " " " 4.60% (Series A) 12,052 " " " " 5.125% 64,000 " " " " 4.60% (Series B) 50,637 " " " " 6% 61,924 " " " " 9.40% 0 " " " ($100 par value) 8.12% 0 " " " " 7.70% 0 " " " " 8.40% 0 " " " ($50 par value) 8.72% 0 " " " ($100 par value) 6.52% 1,000,000 Serial Preferred Stock ($50 par value) (1 vote) ---- 640,000 Serial Preferred Stock ($100 par value) (1 vote) ---- 1,750,000 Serial Preferred Stock ($25 par value) (1/4 vote) ---- 2,000,000 Serial Preferred Stock ($50 par value) (1/2 vote) ---- 700,000 Common Stock ($4.50 par value) ---- 50,000,000 ---------- 56,410,619
-- 4. (a) |__| Amendment(s) adopted by shareholder action. At the date of adoption of the amendment, the number of outstanding shares of each voting group entitled to vote separately on the Amendment, and the vote of such shares was: Number of Number of Number of Votes Number of Undisputed Voting Outstanding Votes Entitled Represented at Shares Voted Group Shares to be Cast the meeting For Against ----- ------------- -------------- --------------------------------------- --- (b) |XX| The Amendment(s) was duly adopted by the incorporators or board of directors without shareholder approval pursuant to Sections 33-6-102(d), 33-10-102 and 33-10-105 of the 1976 South Carolina Code, as amended, and shareholder action was not required. 5. Unless a delayed date is specified, the effective date of these Articles of Amendment shall be the date of the acceptance for filing by the Secretary of State (See Section 33-1-230(b)): SOUTH CAROLINA ELECTRIC & GAS COMPANY Date: June 18, 2003 By:__s/Lynn M. Williams________________ ------------------ Secretary EX-10 5 edcp.txt EXHIBIT 10.01 AMENDMENT OF EDCP Exhibit 10.01 AMENDMENT TO THE SCANA CORPORATION EXECUTIVE DEFERRED COMPENSATION PLAN WHEREAS, SCANA Corporation (the "Company") established the SCANA Corporation Executive Deferred Compensation Plan (the "Plan"), and most recently amended and restated the Plan effective January 1, 2001; and WHEREAS, in accordance with Section 10.9 of the Plan, the Company reserves the right to amend the Plan; NOW, THEREFORE, IT IS RESOLVED effective February 20, 2003, unless otherwise provided herein, the Plan shall be amended as follows (additions bold and underlined, deletions struck-through): 1. Section 3.2 of the Plan is amended to read as follows: 3.2 Participation. An Employee who meets the eligibility requirements of Section 3.1 may become a Participant in this Plan by electing to defer a portion of his Excess Compensation or Performance Share Award on such form and in such manner as determined by the Committee pursuant to Section 4. Eligible Employees who are participants in the Qualified Plan may automatically be deemed to have elected to defer a portion of their Excess Compensation hereunder in accordance with Section 4. 2. Section 4.1(d) of the Plan is amended to read as follows: (d) Deferral Procedures for Basic and Additional Deferrals. All elections under Section 4.1(a) and Section 4.1(b) must be made at such time and in such manner as specified by the Committee prior to the payroll period in which such Excess Compensation is otherwise earned. The Committee may, in its discretion, establish a default procedure whereby an Eligible Employee shall automatically be deemed to have elected to defer under this Plan the same percentage of his or her annual base salary as the deferral percentage in effect for such Eligible Employee under the Qualified Plan immediately prior to the Eligible Employee's participation in a given Year under this Plan. Once a Basic Deferral or Additional Deferral election is made (or deemed to be made) for a Year, it shall remain in effect for all future Excess Compensation otherwise payable in all future pay periods during that Year and any subsequent year until affirmatively changed by the Participant in accordance with the terms of the Plan and the procedures implemented hereunder. Participants may amend their Basic Deferral or Additional Deferral elections at any time, with respect to Excess Compensation to be earned after the date of such modified election. The Committee is permitted but not required to establish deferral procedures pursuant to which Participants are eligible to make separate deferral elections with respect to base salary and short-term incentive awards. Pursuant to such procedures, effective February 20, 2003, deferral elections (or modifications of prior elections) with respect to short-term incentive awards earned for any Year must be made prior to the first day of the sixth month before the end of the applicable performance cycle with respect to which the short-term incentive award is earned. Eligible Employee Basic Deferrals and Additional Deferrals shall be credited to the Participant's EDCP Ledger(s) at such times and in such manner as determined by the Committee, in its sole discretion, but no less frequently than monthly. 3. Section 4.1(e) of the Plan is amended to read as follows: (e) Deferral Procedures for Bonus Deferrals. Effective for elections made for three-year award cycles ending prior to February 20, 2003, eElections made under Section 4.1(c) must be made no later than the end of the second Year of any three-year award cycle established under the Performance Share Award portion of the SCANA Corporation Long-Term Equity Compensation Plan, and shall apply to the Participant's award that is otherwise payable, if at all, in the Year following the end of the three-year award cycleYear beginning immediately after the date the deferral election is made. Effective for elections made for three-year award cycles ending after February 20, 2003, elections made under Section 4.1(c) must be made no later than the first day of the sixth month prior to the end of any three-year award cycle established under the Performance Share Award portion of the SCANA Corporation Long-Term Equity Compensation Plan, and shall apply to the Participant's award that is otherwise payable, if at all, in the Year following the end of the three-year award cycle. Any Bonus Deferral election made for any Year shall apply solely with respect to the award otherwise payable in that Year and not any future Year. Eligible Employee Bonus Deferrals shall be credited to the Participant's EDCP Ledger(s) in such manner as determined by the Committee, in its sole discretion, but no later than as of the last business day of the month following the month in which the Participant's Performance Share Award is otherwise payable. 4. Section 4.2 of the Plan is amended to read as follows: 4.2 Crediting of Employer Matching Deferrals. Effective as of January 1, 2002, a Participant who has elected to have a Basic Deferral under Section 4.1(a) will automatically be credited with an amount equal to the Employer Matching Contribution to which the Participant would have been entitled under the Qualified Plan had his Basic Deferrals under this Plan been made under the Qualified Plan, disregarding any Code Limitations. Effective for deferrals made on or after February 20, 2003, any Participant who has elected to make a deferral under Section 4.1(a) or 4.1(b) for a Plan Year will be credited with an Employer Matching Deferral for such Plan Year of an amount equal to such deferral, provided that the total amount of a Participant's Employer Matching Deferral for any Plan Year shall not exceed an amount equal to 6% of the Participant's Excess Compensation. Such Employer Matching Deferrals shall be credited to each the Participant's "termination of employment" EDCP Ledger at such times and in such manner as the Committee, in its sole discretion determines, but no less frequently than monthly. For periods prior to January 1, 2002, a Participant shall be entitled to an Employer Matching Deferral in accordance with the terms of Appendix A. RESOLVED FURTHER, that the proper officers of the Company are authorized and directed to take all such actions, execute all such documents, and undertake any other actions that are necessary or desirable, in their discretion, to effectuate the foregoing resolution in connection with the implementation of the above described actions. EX-10 6 actionrequest10-06.txt EXHIBIT 10.06 ACTION REQUEST Exhibit 10.06 REQUEST FOR ACTION BY THE SCANA LONG-TERM EQUITY COMPENSATION PLAN COMMITTEE OF THE BOARD WHEREAS, SCANA Corporation has contracted with Merrill Lynch to perform various administrative services with regard to the Nonqualified Stock Options ["Options"] benefit feature of the SCANA Long-Term Equity Compensation Plan ["Plan"]; and WHEREAS, in the structuring of those services Merrill Lynch has advised that, with respect to establishing the Fair Market Value for the non-cashless exercises of Options, its system is designed to identify the closing price on the New York Stock Exchange for each trading date; and WHEREAS, presently Section 2.16 of the Plan defines Fair Market Value to mean, except for cashless exercises, "the opening sale price on the principal securities exchange on which the shares are traded", which, as noted above, the Merrill Lynch system will not identify without considerable expense and delay to SCANA for program changes to their system; and WHEREAS, SCANA regards it practical and prudent to conform the operation of its Plan to accommodate the regular workings of the Merrill Lynch system in so far as it define Fair Market Value for the non-cashless exercise of Options to mean a trading day's closing price on the principal securities exchanges on which the Shares are traded; and WHEREAS, it is more consistent with Internal Revenue Service valuation principles to value a publicly traded stock by benchmarking a share sales price occurring on the subject valuation date itself, thereby recommending use of the closing composite price for the exercise date prospectively indicated by a Participant in a non-cashless exercise; and WHEREAS, the SCANA Long-Term Equity Compensation Committee of the Board ["Committee"] has vested authority pursuant to Section 15.1 of the Plan to amend the definition of Fair Market Value to accomplish the above purpose; NOW, THEREFORE, we the members of the Committee by our respective signatures and check "Approved" below adopt the following amended [the change noted by underlined text] and restated definition of Fair Market Value for Section 2.16 of the Plan: "Fair Market Value" shall be determined on the basis of the opening sale price on the principal securities exchange on which the Shares are traded or, if there is no such sale on the relevant date, then on the last previous day on which a sale was reported, except that as to the "cashless" exercise of Nonqualified Stock Options pursuant to Section 6.6 of the Plan, the "Fair Market Value" of Shares for determining the Compensation amount recognized by the Participant shall be the actual trade price on the principal securities exchange of Shares sold to provide cash to the Participant, and further except that as to the "non-cashless" exercise of Nonqualified Stock Options pursuant to Section 6.6 of the Plan, the "Fair Market Value" of Shares shall be the closing composite price on the principal securities exchanges on which the Shares are traded for that trading date coinciding with the exercise date prospectively indicated by the Participant in his/her "Notice of Intention to Exercise" letter, or if no sales of Shares occur on said date, then for the next subsequent trading date on which such sales occur. s/Bill L. Amick____________ ___X___ ___________ 8-01-02 Bill L. Amick Approved Disapproved Date s/James A. Bennett __X____ ___________ 8-01-02 James A. Bennett Approved Disapproved Date s/William B. Bookhart, Jr. ___X_____ ____________ 8-01-02 William B. Bookhart, Jr. Approved Disapproved Date s/William C. Burkhardt ____X_____ _____________ 8-01-02 William C. Burkhardt Approved Disapproved Date s/Elaine T. Freeman ______X____ _____________ 8-01-02 Elaine T. Freeman Approved Disapproved Date s/D. Maybank Hagood ____X___ ___________ 8-01-02 D. Maybank Hagood Approved Disapproved Date s/Lynne M. Miller ____X___ ___________ 8-01-02 Lynne M.Miller Approved Disapproved Date s/Maceo K. Sloan ____X___ ___________ 8-01-02 Maceo K. Sloan Approved Disapproved Date s/Harold C. Stowe ___X____ ___________ 8-01-02 Harold C. Stowe Approved Disapproved Date s/G. Smedes York ___X___ ___________ 8-01-02 G. Smedes York Approved Disapproved Date EX-10 7 exh10-09.txt EXHIBIT 10.09 DIRECTORS COMPENSATION PLAN Exhibit 10.09 SCANA CORPORATION DIRECTOR COMPENSATION AND DEFERRAL PLAN January 1, 2001 i SCANA CORPORATION DIRECTOR COMPENSATION AND DEFERRAL PLAN TABLE OF CONTENTS Page SECTION 1. ESTABLISHMENT AND PURPOSE..................................1 1.1 ESTABLISHMENT OF THE PLAN.....................................1 1.2 PURPOSE OF THE PLAN...........................................1 SECTION 2. DEFINITIONS................................................2 2.1 DEFINITIONS...................................................2 2.2 GENDER AND NUMBER.............................................4 SECTION 3. ELIGIBILITY AND PARTICIPATION..............................5 3.1 ELIGIBILITY...................................................5 3.2 ELECTION OF COMPENSATION PAYMENT..............................5 3.3 PAYMENT OF COMPANY STOCK......................................5 3.4 STOCK.........................................................6 3.5 ISSUANCE OF COMPANY STOCK.....................................6 3.6 EFFECT OF STOCK DIVIDENDS AND OTHER CHANGES IN CAPITAL STRUCTURE...................................................6 3.7 LIMITATION ON OWNERSHIP.......................................6 SECTION 4. ELECTION TO DEFER..........................................8 4.1 DEFERRAL ELECTION.............................................8 4.2 DEFERRAL PERIOD...............................................8 4.3 ELECTION TO DEFER A PREVIOUSLY DEFERRED AMOUNT................9 SECTION 5. CREDITING AND INVESTMENT OF DEFERRALS.....................10 5.1 DCD LEDGER...................................................10 5.2 ADJUSTMENT OF AMOUNTS CREDITED TO GROWTH INCREMENT LEDGER....10 5.3 ADJUSTMENT OF AMOUNTS CREDITED TO COMPANY STOCK LEDGER.......10 5.4 DEEMED INVESTMENTS NOT ACTUAL INVESTMENTS....................10 5.5 CHARGES AGAINST DCD LEDGER...................................11 SECTION 6. PAYMENT OF DEFERRED AMOUNTS...............................12 6.1 PAYMENT OF DEFERRED AMOUNTS..................................12 6.2 MANNER OF PAYMENT............................................12 6.3 FORM OF PAYMENT..............................................12 6.4 ACCELERATION OF PAYMENTS.....................................13 6.5 FINANCIAL EMERGENCY..........................................13 SECTION 7. BENEFICIARY DESIGNATION...................................14 7.1 DESIGNATION OF BENEFICIARY...................................14 7.2 DEATH OF BENEFICIARY.........................................14 7.3 INEFFECTIVE DESIGNATION......................................14 SECTION 8. CHANGE IN CONTROL PROVISIONS..............................16 8.1 ACCELERATED DISTRIBUTIONS UPON CHANGE IN CONTROL.............16 8.2 TAX COMPUTATION..............................................16 8.3 NO SUBSEQUENT RECALCULATION OF TAX LIABILITY.................16 8.4 SUCCESSORS...................................................17 8.5 AMENDMENT AND TERMINATION AFTER CHANGE IN CONTROL............17 SECTION 9. GENERAL PROVISIONS........................................18 9.1 CONTRACTUAL OBLIGATION.......................................18 9.2 UNSECURED INTEREST...........................................18 9.3 "RABBI" TRUST................................................18 9.4 NONALIENATION OF BENEFITS....................................18 9.5 SEVERABILITY.................................................19 9.6 NO INDIVIDUAL LIABILITY......................................19 9.7 APPLICABLE LAW...............................................19 SECTION 10. PLAN ADMINISTRATION, AMENDMENT AND TERMINATION...........20 10.1 IN GENERAL...................................................20 10.2 CLAIMS PROCEDURE.............................................20 10.3 FINALITY OF DETERMINATION....................................20 10.4 DELEGATION OF AUTHORITY......................................20 10.5 EXPENSES.....................................................20 10.6 TAX WITHHOLDING..............................................20 10.7 INCOMPETENCY.................................................20 10.8 ACTION BY COMPANY............................................21 10.9 NOTICE OF ADDRESS............................................21 10.10 AMENDMENT AND TERMINATION....................................21 SECTION 11. EXECUTION................................................22 SCANA CORPORATION DIRECTOR COMPENSATION AND DEFERRAL PLAN SECTION 1. ESTABLISHMENT AND PURPOSE 1.1 Establishment of the Plan. SCANA Corporation (the "Company") established the SCANA Corporation Nonemployee Director Stock Plan, effective as of January 1, 1997. Effective as of January 1, 2001, the plan is renamed the "SCANA Corporation Director Compensation and Deferral Plan" (hereinafter called the "Plan") and amended and restated to include a deferred compensation component. 1.2 Purpose of the Plan. The purpose of the Plan is to promote the achievement of long-term objectives of the Company by linking the personal interests of Nonemployee Directors, as defined in Section 2(r) herein, to those of the Company's shareholders and to attract and retain Nonemployee Directors of outstanding competence by mandating that sixty percent (60%) (plus a round-up amount in lieu of any fractional share) of the Retainer Fee of each Participant as defined in Section 2(u) herein, be paid in Company Stock, unless such amount is voluntarily deferred to a future date in accordance with the Plan's terms. The Plan is intended to conform to the provisions of Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any replacement rule in effect from time to time ("Rule 16b-3"). The Plan also provides a means by which Nonemployee Directors may defer certain additional amounts to some future period. SECTION 2. DEFINITIONS 2.1 Definitions. Whenever used herein, the following terms shall have the meanings set forth below, unless otherwise expressly provided herein or unless a different meaning is plainly required by the context, and when the defined meaning is intended, the term is capitalized: (a) "Act" means the Securities Exchange Act of 1934, as amended. (b) "Beneficial Owner" shall have the meaning ascribed to such term in Rule 13d-3 of the General Rules and Regulations under the Exchange Act. (c) "Beneficiary" means any person or entity who, upon the Participant's death, is entitled to receive the Participant's benefits under the Plan in accordance with Section 7 hereof. (d) "Board of Directors" means the board of directors of the Company. (e) "Change in Control" means a change in control of the Company of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Exchange Act, whether or not the Company is then subject to such reporting requirements; provided that, without limitation, such a Change in Control shall be deemed to have occurred if: (i) Any Person (as defined in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a "group" as defined in Section 13(d)) is or becomes the Beneficial Owner, directly or indirectly, of twenty-five percent (25%) or more of the combined voting power of the outstanding shares of capital stock of the Company; (ii) During any period of two (2) consecutive years (not including any period prior to the execution of this Plan) there shall cease to be a majority of the Board of Directors comprised as follows: individuals who at the beginning of such period constitute the Board of Directors and any new director(s) whose election by the Board of Directors or nomination for election by the Company's stockholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved; (iii) The issuance of an Order by the Securities and Exchange Commission (SEC), under Section 9(a)(2) of the Public Utility Holding Company Act of 1935 (the "1935 Act"), authorizing a third party to acquire five percent (5%) or more of the Company's voting shares of capital stock; or (iv) The shareholders of the Company approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting shares of capital stock of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting shares of capital stock of the surviving entity) at least eighty percent (80%) of the combined voting power of the voting shares of capital stock of the Company or such surviving entity outstanding immediately after such merger or consolidation; or the shareholders of the Company approve a plan of complete liquidation of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets. (f) "Code" means the Internal Revenue Code of 1986, as amended. (g) "Company" means SCANA Corporation, a South Carolina corporation, or any successor thereto. (h) "Company Stock" means the no par value common stock of the Company. In the event of a change in the capital structure of the Company (as provided in Section 3.6), the shares resulting from such a change shall be deemed to be Company Stock within the meaning of the Plan. (i) "Company Stock Ledger" means an appropriate bookkeeping record established in the DCD Ledger for which amounts credited are converted into hypothetical credited shares of Company Stock. (j) "Compensation" means Retainer Fees, meeting attendance fees and conference fees payable to such a Participant during a Service Period by the Company. (k) "Director" means an individual who is a member of the Board of Directors. (l) "DCD Ledger" means an appropriate bookkeeping record which shall be established for each Participant which shall reflect: (1) the amounts deferred on behalf of each Participant; and (2) the crediting of deemed investments (and hypothetical earnings on those deemed investments) with respect to amounts deferred on behalf of each Participant. (m) "Exchange Act" means the Securities Exchange Act of 1934, as amended. (n) "Fair Market Value" of Company Stock shall mean: (i) if the Company Stock is original issue stock, the average of the high and low sale prices of a share of the Company Stock reported on the New York Stock Exchange Composite Tape as published in The Wall Street Journal for the trading date immediately preceding the date Company Stock is awarded to a Participant; (ii) if the Company Stock is purchased on the open market, the cost incurred by the Company to purchase such Company Stock; (iii) in the case of any distribution, the closing price for shares of Company Stock on the New York Stock Exchange on the date of distribution; and (iv) in the case of any other transaction hereunder designed to track the investment or reinvestment of Company Stock, the closing price for shares of Company Stock on the New York Stock Exchange on the measuring date. (o) "Growth Increment" means the amount of interest credited to amounts credited to a Participant's Growth Increment Ledger. (p) "Growth Increment Ledger" means an appropriate bookkeeping record established in the DCD Ledger for which amounts are credited with Growth Increments. (q) "Investor Plan" means the SCANA Investor Plus Plan. (r) "Nonemployee Director" means a Director who is not currently employed by the Company or any subsidiary of the Company (without regard to whether such individual was previously employed by the Company). (s) "Participant" means a Nonemployee Director satisfying the eligibility requirements of Section 3. (t) "Plan" means the SCANA Corporation Director Compensation and Deferral Plan. (u) "Retainer Fees" means the amount of compensation payable to each Participant with respect to services rendered to the Company as a Director for the Service Period. Such term does not include fees for attending meetings of the Board of Directors or committees of the Board of Directors and also does not include conference fees. (v) "Rule 16b-3" means Rule 16b-3 of the Act, as amended, or any replacement rule in effect from time to time. (w) "Service Period" means a calendar year. 2.2 Gender and Number. Except when otherwise indicated by the context, any masculine terminology used herein also shall include the feminine and the feminine shall include the masculine, and the use of any term herein in the singular may also include the plural and the plural shall include the singular. SECTION 3. ELIGIBILITY AND PARTICIPATION 3.1 Eligibility. All Nonemployee Directors shall automatically be eligible to participate in this Plan. ----------- 3.2 Election of Compensation Payment. (a) Unless otherwise deferred in accordance with Section 4, sixty percent (60%) of each Participant's Retainer Fee amounts shall be paid to the Participant as soon as practicable after the beginning of each calendar quarter (as determined by the Board of Directors (or its delegate)) and such payment shall be made entirely in shares of Company Stock. (b) Unless otherwise deferred in accordance with Section 4, the remaining forty percent (40%) of each Participant's Retainer Fee as well as one hundred percent (100%) of each Participant's meeting attendance and conference fees shall be paid to the Participant at such times determined by the Board of Directors or its delegate. Within a reasonable period of time before any amounts are paid under this Section 3.2(b), each Participant shall elect (in accordance with procedures established by the Board of Directors or its delegate) whether to receive the amounts otherwise payable under this Section 3.2(b) all in cash or all in shares of Company Stock. (c) With respect to all payments in Company Stock under this Section 3.2, and subject to Section 3.3, each Participant shall be entitled to a number of shares of Company Stock equal to the smallest number of whole shares of Company Stock which, when multiplied by Fair Market Value would equal no less than the equivalent amount of Compensation otherwise payable to the Participant. Any remaining amounts owed shall be paid in cash. 3.3 Payment of Company Stock. In connection with amounts to be paid during a Service Period under Section 3.2 which are paid in the form of Company Stock, each Participant may elect to have the shares of Company Stock to be issued to him pursuant to the Plan during the Service Period registered in his name. In such case, all shares of Company Stock to be paid shall be issued as promptly as practicable after the amounts are otherwise payable. If a Participant does not make such an election, all shares issued pursuant to the Plan during the Service Period will be deposited into an account in his name in the Investor Plan. If the Participant is elected to be a Nonemployee Director during the Service Period, the election to have the shares registered in his name may be made at any time between his election and the next regularly scheduled Board of Directors' meeting. All cash dividends paid on shares deposited in the Investor Plan will be reinvested in additional shares of Company Stock unless the Participant notifies the Investor Plan in accordance with the terms thereof that he does not want to reinvest such dividends. During the last quarter of each calendar year in which there is a change in the prospectus for the Investor Plan, all Participants who have not been provided previously with a copy of such changed prospectus shall be provided with a copy of the then-current prospectus. In addition, each newly-elected Participant who is not a participant in the Investor Plan shall be given an Investor Plan prospectus shortly after his election. 3.4 Stock. Company Stock issued pursuant to the Plan may be either original issue or stock purchased on the open market. The Company has reserved an aggregate of 100,000 shares of original issue Company Stock for issuance pursuant to the Plan and has registered 100,000 shares with the Securities and Exchange Commission on a Form S-8. The maximum number of shares that may be issued pursuant to this Plan is 100,000 shares subject to adjustment as provided in Section 3.6. In the event of a change in the capital structure of the Company (as provided in Section 3.6), the shares resulting from such change shall be deemed to be Company Stock within the meaning of the Plan. The aggregate number of shares of Company Stock reserved shall be reduced by the issuance of shares under the Plan. 3.5 Issuance of Company Stock. Notwithstanding anything in this Plan to the contrary: (a) The Company shall not be required to issue or deliver any certificate for shares of Company Stock to a Participant before (i) such shares have been admitted to listing on the New York Stock Exchange, (ii) the Company has received any required registration or other qualification of such shares under any state or federal law or regulation that the Company's counsel shall determine is necessary or advisable and (iii) the Company is satisfied that all applicable legal requirements have been complied with. The Company may place on a certificate representing Company Stock any legend deemed necessary by the Company's counsel to comply with federal or state securities laws. Until the Participant has been issued a certificate for the shares of Company Stock acquired, the Participant shall possess no shareholder rights with respect to the shares. (b) If at any time there may not be sufficient shares available under the Plan to permit the awards of Company Stock, the awards shall be reduce pro rata (to zero, if necessary) so as not to exceed the number of shares then available for issuance under the Plan. 3.6 Effect of Stock Dividends and Other Changes in Capital Structure. Appropriate adjustments shall be made automatically to the number and kind of shares to be issued under the Plan, as well as to any deferred amounts credited to a Participant's Company Stock Ledger and any other relevant provisions of the Plan, if there are any changes in the Company Stock by reason of a stock dividend, stock split, combination of shares, spin-off, reclassification, recapitalization, merger, consolidation or other change in the Company's capital stock (including, but not limited to, the creation or issuance to shareholders generally of rights, options, or warrants for the purchase of common stock or preferred stock of the Company). If the adjustment would produce fractional shares, the fractional shares shall be eliminated by rounding to the nearest whole share. Any adjustments shall be made in a manner consistent with Rule 16b-3. Any such adjustments shall neither enhance nor diminish the rights of a Participant and the Company shall pay all costs of administering the Plan, including all commissions with respect to open market purchases. 3.7 Limitation on Ownership. No single officer or director may acquire under the Plan more than one percent of the shares of Company Stock outstanding at the time the Plan is adopted. In addition, together with all plans of SCANA Corporation (not otherwise exempt from shareholder approval under Rule 312.03 of the New York Stock Exchange) this Plan shall not authorize the issuance of more than five percent of Company Stock outstanding at the time the Plan is adopted. SECTION 4. ELECTION TO DEFER 4.1 Deferral Election. Subject to the conditions set forth in this Plan, and such procedures established by the Board of Directors, a Participant may elect to defer amounts of Compensation as follows: (a) At least 10 days before the beginning of each Service Period, a Participant irrevocably may elect, by written notice to the Company's Secretary (or his designee), to defer a portion of his Compensation for such Service Period. In the case of a Participant elected to the Board of Directors during the Service Period, the Participant may elect, within 30 days of his election to the Board of Directors, to defer a portion of his Compensation payable subsequent to his election. Such election shall specify either that: (i) the Participant elects to defer one hundred percent (100%) of his Compensation and designates that all such deferrals shall be credited to the Company Stock Ledger on his behalf; or (ii) the Participant elects to defer up to forty percent (40%) of his Retainer Fee and up to one hundred percent (100%) of his meeting attendance and conference fees and designates that all such deferrals shall be credited on his behalf one hundred percent (100%) to the Growth Increment Ledger or one hundred percent (100%) to the Company Stock Ledger. In addition, the Participant may elect to defer the remaining sixty percent (60%) of his Retainer Fee provided that such deferral shall be credited on his behalf one hundred percent (100%) only to the Company Stock Ledger. (b) The deferral election specified in (a) above shall be applied to the Participant's Compensation for each Service Period to which the deferral election applies. (c) If a Participant makes a deferral election under Section 4.1(a) whereby amounts are credited to the Company Stock Ledger on his behalf, such Participant shall also elect, in conjunction with that deferral election, whether amounts equal to dividends attributable to shares of Company Stock credited to his Company Stock Ledger shall be paid directly to him in cash or deemed reinvested pursuant to Section 5.3. 4.2 Deferral Period. With respect to deferrals made in accordance with Section 4.1, each Participant must elect a deferral period for each annual deferral. Subject to the additional deferral provisions of Section 4.3 and the acceleration provisions of Section 6.4, a Participant's deferral period may be for a specified number of years or until a specified date, subject to any limitations that the Board of Directors (or its delegate) in its discretion may choose to apply. 4.3 Election to Defer a Previously Deferred Amount. ---------------------------------------------- (a) Subject to the acceleration provisions of Section 6.4, a Participant may request that the Board of Directors (or its delegate) approve an additional deferral period of at least twelve (12) months with respect to any previously deferred amount. Any such request must be made by written notice to the Board of Directors (or its delegate) at least twelve (12) months before the expiration of the deferral period for any previously deferred amount with respect to which an additional deferral election is requested. Such additional deferral election request may be made for each separate deferral previously made. (b) Notwithstanding the additional deferral election requests made by the Participant pursuant to Subsection 4.3(a) above, neither the deferral period elected nor the related manner of payment elected shall be automatically binding upon the Company by the mere fact of the election requests having been made. The Board of Directors (or its delegate) shall review each such election submitted and determine whether or not it is in the best interest of the Company to accept the elections as submitted. Such Board of Directors (or delegate) review will be made on a case-by-case basis and all determinations shall be made by the Board of Directors (or its delegate) in its sole and complete discretion after consideration of such factors as it deems relevant, including broad economic and policy implications to the Company of approving any request. The Board of Directors, or its delegate, shall notify each Participant in writing within the first sixty (60) days of the twelve (12) month period noted in Section 4.3(a) above as to whether the deferral period and related manner of payment elections are accepted by the Board of Directors as submitted, and if not, the terms upon which such elections would be accepted; in the latter instance, the Participant shall, no later than on the seventy-fifth (75th) day of the twelve (12) month period noted in Section 4.3(a), inform the Board of Directors (or its delegate) in writing of his acceptance or rejection of the terms proffered by the Board of Directors (or its delegate). All determinations made by the Board of Directors or its delegate shall be final and binding on all parties. SECTION 5. CREDITING AND INVESTMENT OF DEFERRALS 5.1 DCD Ledger. The Board of Directors shall establish for each Participant a DCD Ledger which shall reflect the amounts deferred on behalf of each Participant. In the sole discretion of the Board of Directors, one or more appropriate bookkeeping records shall be established in the DCD Ledger to reflect the deemed investments (and hypothetical earnings) made by each Participant in accordance with this Section 5 which shall include, but not be limited to, the Company Stock Ledger and the Growth Increment Ledger. 5.2 Adjustment of Amounts Credited to Growth Increment Ledger. All deferrals credited to each Participant's Growth Increment Ledger will be credited with Growth Increments based on the prime interest rate charged from time to time by the Wachovia Bank, N.A. The Board of Directors will have the authority to change the interest rate that may be applied to the Growth Increment Ledger. The Participant's Growth Increment Ledger shall be credited on the first day of each calendar quarter, with a Growth Increment computed on the average balance in the Participant's Growth Increment Ledger during the preceding calendar quarter. The Growth Increment shall be equal to the amount in said Growth Increment Ledger multiplied by the average interest rate selected by the Board of Directors during the preceding calendar quarter times a fraction the numerator of which is the number of days during such quarter and the denominator of which is 365. Growth Increments will continue to be credited until all of a Participant's benefits have been paid out of the Plan. 5.3 Adjustment of Amounts Credited to Company Stock Ledger. All deferrals credited to each Participant's Company Stock Ledger will be converted into hypothetical credited shares of Company Stock based on the Fair Market Value of the Company Stock on the date the deferrals would otherwise have been paid to the Participant. The value of each Participant's Company Stock Ledger shall be adjusted from time to time to reflect increases and decreases in shares of Company Stock as well as any stock or cash dividends, stock splits, or other changes in the capital structure of the Company (as provided in Section 3.6), that may from time to time be declared. Unless a Participant has elected pursuant to Section 4.1(c) that amounts equivalent to dividends on Company Stock be paid to the Participant, all dividends attributable to hypothetical shares of Company Stock credited to each Participant's Company Stock Ledger shall be converted to additional credited shares of Company Stock as though reinvested as of the next business day after the dividend is paid. If a Participant has elected pursuant to Section 4.1(c) that deemed dividends be paid to the Participant in cash, such amount shall be paid to the Participant as soon as practicable after the deemed dividend is credited to the Participant's Company Stock Ledger. 5.4 Deemed Investments Not Actual Investments. Nothing in this Plan shall be construed to require the investment of any deferrals in shares of Company Stock or any other investment or give a Participant any rights whatsoever with respect to any shares of Company Stock or with respect to any other investment. 5.5 Charges Against DCD Ledger. There shall be charged against each Participant's DCD Ledger any payments made to the Participant or to his Beneficiary in accordance with Section 6 hereof. SECTION 6. PAYMENT OF DEFERRED AMOUNTS 6.1 Payment of Deferred Amounts. The aggregate amounts payable under Section 6.2 as charges against the Participant's amount credited in the DCD Ledger shall be paid commencing with the conclusion of the deferral period selected by the Participant pursuant to Section 4.2 or Section 4.3 hereof. The payments shall be made in the manner selected by the Participant under Section 6.2 of this Plan. 6.2 Manner of Payment. At the same time as the election made pursuant to Section 4.1, and subject to the acceleration provisions of Section 6.4, each Participant must also irrevocably elect the manner in which his deferred amounts will be paid. A Participant may elect to have a different manner of payment apply to each separate deferral election. Participants must choose to have payment made in accordance with any of the following distribution forms: (i) a single payment, or (ii) a designated number of installments payable monthly, quarterly or annually, as elected, which shall be paid or commence to be paid as soon as practicable after the conclusion of the deferral period elected pursuant to Section 4.2 or Section 4.3. Unless otherwise specifically elected, payments of all deferred amounts will be made in a single payment made as soon as practicable after the conclusion of the deferral period elected pursuant to Section 4.2 or Section 4.3. 6.3 Form of Payment. Amounts credited to a Participant's Growth Increment Ledger and Company Stock Ledger shall be paid as follows: (a) Amounts credited to the Participant's Growth Increment Ledger shall be paid in cash. If a Participant's benefit hereunder is to be paid in installments, the amount of each payment shall be equal to the amount credited to the Participant's Growth Increment Ledger at the time of payment multiplied by a fraction, the numerator of which is one and the denominator of which is the number of installment payments remaining. (b) Amounts credited to the Participant's Company Stock Ledger shall be paid in shares of Company Stock with any amount representing a partial share of Company Stock paid in cash. A payment of an amount credited to the Participant's Company Stock Ledger shall be converted into actual shares of Company Stock as soon as practicable prior to each payment being made to the Participant. If a Participant's benefit hereunder is to be paid in installments, the amount of each payment shall be equal to the number of shares of Company Stock then credited to the Participant's Company Stock Ledger multiplied by a fraction, the numerator of which is one and the denominator of which is the number of installment payments remaining. Any amounts attributable to a partial share of Company Stock as of any installment payment date shall be paid in cash with each installment. 6.4 Acceleration of Payments. Notwithstanding the election made pursuant to Section 4.2 or Section 4.3: (a) payments shall be paid or begin to be paid as soon as practicable following the Participant's departure from the Board of Directors by reason of death, resignation, or otherwise; (b) if a Participant dies prior to the payment of all or a portion of the amounts credited to his DCD Ledger, the balance of any amount payable shall be paid in a cash lump sum to the Beneficiaries designated under Section 7 hereof; (c) if a Participant ceases to be a Nonemployee Director but thereafter becomes an employee of the Company (or any of its subsidiaries or affiliates), all amounts otherwise deferred under this Plan shall be paid as soon as practicable after such individual becomes an employee of the Company (or any of its subsidiaries or affiliates) in a single sum payment; (d) if a Participant's DCD Ledger balance is less than $5,000 at the time for payment specified, such amount shall be paid in a single sum payment; and (e) if applicable, the provisions of Section 8 shall apply. 6.5 Financial Emergency. The Board of Directors (or its delegate), at its sole discretion, may alter the timing or manner of payment of deferred amounts if the Participant establishes, to the satisfaction of the Board of Directors (or its delegate), an unanticipated and severe financial hardship that is caused by an event beyond the Participant's control. In such event, the Board of Directors (or its delegate) may: (a) provide that all, or a portion of, the amount previously deferred by the Participant immediately shall be paid in a lump sum cash payment, (b) provide that all, or a portion of, the installments payable over a period of time immediately shall be paid in a lump sum cash payment, or (c) provide for such other installment payment schedules as it deems appropriate under the circumstances, as long as the amount distributed shall not be in excess of that amount which is necessary for the Participant to satisfy the financial emergency. Severe financial hardship will be deemed to have occurred in the event of the Participant's or a dependent's sudden, lengthy and serious illness as to which considerable medical expenses are not covered by insurance or relative to which there results a significant loss of family income, or other unanticipated events of similar magnitude. The Board of Directors' decision (or that of its delegate) in passing on the severe financial hardship of the Participant and the manner in which, if at all, the payment of deferred amounts shall be altered or modified shall be final, conclusive, and not subject to appeal. SECTION 7. BENEFICIARY DESIGNATION 7.1 Designation of Beneficiary. (a) A Participant shall designate a Beneficiary or Beneficiaries who, upon the Participant's death, are to receive the amounts that otherwise would have been paid to the Participant. All designations shall be in writing and signed by the Participant. The designation shall be effective only if and when delivered to the Company during the lifetime of the Participant. The Participant also may change his Beneficiary or Beneficiaries by a signed, written instrument delivered to the Company. The payment of amounts shall be in accordance with the last unrevoked written designation of Beneficiary that has been signed and delivered to the Company. All Beneficiary designations shall be addressed to the Company's Secretary and delivered to his office, and shall be processed as indicated in subsection (b) below by the Secretary or by his authorized designee. (b) The Company's Secretary (or his authorized designee) shall, upon receipt of the Beneficiary designation: (1) ascertain that the designation has been signed, and if it has not been, return it to the Participant for his signature; (2) if signed, stamp the designation "Received", indicate the date of receipt, and initial the designation in the proximity of the stamp. 7.2 Death of Beneficiary. (a) In the event that all of the Beneficiaries named pursuant to Section 7.1 predecease the Participant, the amounts that otherwise would have been paid to said Beneficiaries shall, where the designation fails to redirect to alternate Beneficiaries in such circumstance, be paid to the Participant's estate as the alternate Beneficiary. (b) In the event that two or more Beneficiaries are named, and one or more but less than all of such Beneficiaries predecease the Participant, each surviving Beneficiary shall receive any proportion or amount of funds designated or indicated for him per the designation under Section 7.1, and the indicated share of each predeceased Beneficiary which the designation fails to redirect to an alternate Beneficiary in such circumstance shall be paid to the Participant's estate as an alternate Beneficiary. 7.3 Ineffective Designation. (a) In the event the Participant does not designate a Beneficiary, or if for any reason such designation is entirely ineffective, the amounts that otherwise would have been paid to the Beneficiary shall be paid to the Participant's estate as the alternate Beneficiary. (b) In the circumstance that designations are effective in part and ineffective in part, to the extent that a designation is effective, distribution shall be made so as to carry out as closely as discernable the intent of the Participant, with the result that only to the extent that a designation is ineffective shall distribution instead be made to the Participant's estate as an alternate Beneficiary. SECTION 8. CHANGE IN CONTROL PROVISIONS 8.1 Accelerated Distributions Upon Change in Control. Notwithstanding anything in this Plan to the contrary, upon the occurrence of a Change in Control where there has not been a termination of the SCANA Corporation Key Employee Severance Benefits Plan prior thereto, the amounts (or remaining amounts) credited to each Participant's DCD Ledger under this Plan as of the date of such Change in Control (referred to as each Participant's "DCD Benefit") shall become immediately due and payable. All DCD Benefits payable under this Section 8.1 shall be paid to each Participant (and his or her Beneficiary) in the form of a single lump sum cash payment, together with an amount (the "Gross-Up Payment") such that the net amount retained by each Participant after deduction of any excise tax imposed by Section 4999 of the Code (or any similar tax that may hereafter be imposed) on such benefits (the "Excise Tax") and any Federal, state, and local income tax and Excise Tax upon the DCD Benefit and the Gross-Up Payment provided for by this Section 8 shall be equal to the value of the Participant's DCD Benefit. Such payment shall be made by the Company (or to the extent assets are transferred to the SCANA Corporation Director Compensation Trust by the trustee of such trust in accordance with the trust's terms) to the Participant (or his or her Beneficiary) as soon as practicable following the Change in Control, but in no event later than the date specified by the terms of the SCANA Corporation Director Compensation Trust. In all events, if the SCANA Corporation Key Employee Severance Benefits Plan was terminated prior to such Change in Control, then the provisions of this Section shall not apply and Participants' benefits shall be determined and paid under the otherwise applicable provisions of the Plan. 8.2 Tax Computation. For purposes of determining the amount of the Gross-Up Payment referred to in Section 8.1, whether any of a Participant's DCD Benefit will be subject to the Excise Tax, and the amounts of such Excise Tax: (i) there shall be taken into account all other payments or benefits received or to be received by a Participant in connection with a Change in Control of the Company (whether pursuant to the terms of this Plan or any other plan, arrangement, or agreement with the Company, any person whose actions result in a Change in Control of the Company or any person affiliated with the Company or such person); and (ii) the amount of any Gross-Up Payment payable with respect to any Participant (or his or her Beneficiary) by reason of such payment shall be determined in accordance with a customary "gross-up formula," as determined by the Management Development and Corporate Performance Committee of the Board of Directors in its sole discretion. 8.3 No Subsequent Recalculation of Tax Liability. The Gross-Up Payments described in the foregoing provisions of this Section 8 are intended and hereby deemed to be a reasonably accurate calculation of each Participant's actual income tax and Excise Tax liability under the circumstances (or such tax liability of his or her Beneficiary), the payment of which is to be made by the Company or the SCANA Corporation Director Compensation Trust. All such calculations of tax liability shall not be subject to subsequent recalculation or adjustment in either an underpayment or overpayment context with respect to the actual tax liability of the Participant (or his or her Beneficiary) ultimately determined as owed. 8.4 Successors. Notwithstanding anything in this Plan to the contrary, upon the occurrence of a Change in Control, and only if the SCANA Corporation Key Employee Severance Benefits Plan ("KESBP") was terminated prior to such Change in Control, the Company will require any successor (whether direct or indirect, by purchase, merger, consolidation, or otherwise) of all or substantially all of the business and/or assets of the Company or of any division or subsidiary thereof to expressly assume and agree to perform this Plan in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place, subject to the remaining provisions of this Section 8.4. In the event of such a Change in Control where the KESBP is terminated, Participants shall become entitled to benefits hereunder in accordance with the terms of this Plan, based on amounts credited to each Participant's DCD Ledger as of the date of such Change in Control plus accumulated Growth Increments attributable thereto (adjusted to reflect any change from the most recent Growth Increment calculation to the end of the month prior to the month such amounts are distributed to each Participant). In such case, any successor to the Company shall not be required to provide for additional deferral of benefits beyond the date of such Change in Control. In addition, and notwithstanding Section 8.5 to the contrary, if there is a Change in Control and the KESBP is terminated prior to such Change in Control, a successor to the Company may amend this Plan to provide for an automatic lump sum distribution of the then current value of Participants' DCD Ledger, including accumulated Growth Increments attributable thereto (adjusted to reflect any change since the most recent Growth Increment calculation) hereunder without such amendment being treated as an amendment reducing any benefits earned. 8.5 Amendment and Termination After Change in Control. Notwithstanding the foregoing, and subject to this Section 8, no amendment, modification or termination of the Plan may be made, and no Participants may be added to the Plan, upon or following a Change in Control if it would have the effect of reducing any benefits earned (including optional forms of distribution) prior to such Change in Control without the written consent of all of the Plan's Participants covered by the Plan at such time. In all events, however, the Company reserves the right to amend, modify or delete the provisions of Section 8 at any time prior to a Change in Control, pursuant to a Board of Directors resolution adopted by a vote of two-thirds (2/3) of the Board of Directors members then serving on the Board of Directors. SECTION 9. GENERAL PROVISIONS 9.1 Contractual Obligation. It is intended that the Company is under a contractual obligation to make payments from a Participant's DCD Ledger when due. Payment of amounts credited to a Participant's DCD Ledger shall be made out of the general funds of the Company as determined by the Board of Directors without any restriction of the assets of the Company relative to the payment of such contractual obligations; the Plan is, and shall operate as, an unfunded plan. 9.2 Unsecured Interest. No Participant or Beneficiary shall have any interest whatsoever in any specific asset of the Company. To the extent that any person acquires a right to receive payment under this Plan, such right shall be no greater than the right of any unsecured general creditor of the Company. 9.3 "Rabbi" Trust. In connection with this Plan, the Board of Directors shall establish a grantor trust (known as the "SCANA Corporation Director Compensation Trust") for the purpose of accumulating funds to satisfy the obligations incurred by the Company under this Plan (and such other plans and arrangements as determined from time to time by the Company). At any time prior to a Change in Control, as that term is defined in such Trust, the Company may transfer assets to the Trust to satisfy all or part of the obligations incurred by the Company under this Plan, as determined in the sole discretion of the Board of Directors, subject to the return of such assets to the Company at such time as determined in accordance with the terms of such Trust. Any assets of such Trust shall remain at all times subject to the claims of creditors of the Company in the event of the Company's insolvency; and no asset or other funding medium used to pay benefits accrued under the Plan shall result in the Plan being considered as other than "unfunded" under ERISA. Notwithstanding the establishment of the Trust, the right of any Participant to receive future payments under the Plan shall remain an unsecured claim against the general assets of the Company. 9.4 Nonalienation of Benefits. (a) No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber or charge the same shall be void; nor shall any such disposition be compelled by operation of law. (b) No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to benefits under the Plan. (c) If any Participant or Beneficiary hereunder should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right or benefit hereunder, then such right or benefit shall, in the discretion of the Board of Directors, cease, and the Board of Directors shall direct in such event that the Company hold or apply the same or any part thereof for the benefit of the Participant or Beneficiary in such manner and in such proportion as the Board of Directors may deem proper. 9.5 Severability. If any particular provision of the Plan shall be found to be illegal or unenforceable for any reason, the illegality or lack of enforceability of such provision shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or unenforceable provision had not been included. 9.6 No Individual Liability. It is declared to be the express purpose and intention of the Plan that no liability whatsoever shall attach to or be incurred by the shareholders, officers, or directors of the Company or any representative appointed hereunder by the Company, under or by reason of any of the terms or conditions of the Plan. 9.7 Applicable Law. This Plan shall be governed and construed in accordance with the laws of the State of South Carolina except to the extent governed by applicable Federal law. The terms of this Plan are also subject to all present and future rulings of the Securities and Exchange Commission with respect to Rule 16b-3. If any provision of the Plan would cause the Plan to fail to meet the requirements of Rule 16b-3, then that provision of the Plan shall be void and of no effect. SECTION 10. PLAN ADMINISTRATION, AMENDMENT AND TERMINATION 10.1 In General. This Plan shall be administered by the Board of Directors, which shall have the sole authority to construe and interpret the terms and provisions of the Plan and determine the amount, manner and time of payment of any benefits hereunder. The Board of Directors shall not exercise any discretion with respect to the administration of this Plan, except as may be permitted by Rule 16b-3. The Board of Directors shall maintain records, make the requisite calculations and disburse payments hereunder, and its interpretations, determinations, regulations and calculations shall be final and binding on all persons and parties concerned. The Board of Directors may adopt such rules as it deems necessary, desirable or appropriate in administering this Plan and the Board of Directors may act at a meeting, in a writing without a meeting, or by having actions otherwise taken by a member of the Board of Directors pursuant to a delegation of duties from the Board of Directors. 10.2 Claims Procedure. Any person dissatisfied with the Board of Directors' determination of a claim for benefits hereunder must file a written request for reconsideration with the Board of Directors (or its delegate). This request must include a written explanation setting forth the specific reasons for such reconsideration. The Board of Directors shall review its determination promptly and render a written decision with respect to the claim, setting forth the specific reasons for such denial written in a manner calculated to be understood by the claimant. Such claimant shall be given a reasonable time within which to comment, in writing, to the Board of Directors with respect to such explanation. The Board of Directors shall review its determination promptly and render a written decision with respect to the claim. Such decision upon matters within the scope of the authority of the Board of Directors shall be conclusive, binding, and final upon all claimants under this Plan. 10.3 Finality of Determination. The determination of the Board of Directors as to any disputed questions arising under this Plan, including questions of construction and interpretation, shall be final, binding, and conclusive upon all persons. 10.4 Delegation of Authority. The Board of Directors may, in its discretion, delegate its duties to a committee of the Board of Directors or an officer or other employee of the Company, or to a committee composed of officers or employees of the Company. 10.5 Expenses. The cost of payment from this Plan and the expenses of administering the Plan shall be borne by the Company. 10.6 Tax Withholding. The Company shall have the right to deduct from all payments made from the Plan any federal, state, or local taxes required by law to be withheld with respect to such payments. 10.7 Incompetency. Any person receiving or claiming benefits under the Plan shall be conclusively presumed to be mentally competent and of age until the Company receives written notice, in a form and manner acceptable to it, that such person is incompetent or a minor, and that a guardian, conservator, statutory committee under the South Carolina Code of Laws, or other person legally vested with the care of his estate has been appointed. In the event that the Company finds that any person to whom a benefit is payable under the Plan is unable to properly care for his affairs, or is a minor, then any payment due (unless a prior claim therefor shall have been made by a duly appointed legal representative) may be paid to the spouse, a child, a parent, or a brother or sister, or to any person deemed by the Company to have incurred expense for the care of such person otherwise entitled to payment. In the event a guardian or conservator or statutory committee of the estate of any person receiving or claiming benefits under the Plan shall be appointed by a court of competent jurisdiction, payments shall be made to such guardian or conservator or statutory committee provided that proper proof of appointment is furnished in a form and manner suitable to the Company. Any payment made under the provisions of this Section 10.7 shall be a complete discharge of liability therefor under the Plan. 10.8 Action by Company. Any action required or permitted to be taken hereunder by the Company or its Board of Directors shall be taken by the Board of Directors, or by any person or persons authorized by the Board of Directors. 10.9 Notice of Address. Any payment made to a Participant or to his Beneficiary at the last known post office address of the distributee on file with the Company, shall constitute a complete acquittance and discharge to the Company and any director or officer with respect thereto, unless the Company shall have received prior written notice of any change in the condition or status of the distributee. Neither the Company nor any director or officer shall have any duty or obligation to search for or ascertain the whereabouts of the Participant or his Beneficiary. 10.10 Amendment and Termination. The Company expects the Plan to be permanent but, since future conditions affecting the Company cannot be anticipated or foreseen, the Company reserves the right to amend, modify, or terminate the Plan at any time by action of its Board of Directors (including, but not limited to, as may be necessary to ensure compliance with Rule 16b-3); provided, however, that any such action shall not diminish retroactively any amounts which have been credited to any Participant's DCD Ledger. If the Board of Directors amends the Plan to cease future deferrals hereunder or terminates the Plan, the Board of Directors may, in its sole discretion, direct that the value of each Participant's DCD Ledger be paid to each Participant (or Beneficiary, if applicable) in an immediate lump sum payment. In the absence of any such direction from the Board of Directors, the Plan shall continue as a "frozen" plan under which no future deferrals will be recognized (however, Growth Increments and dividends attributable to hypothetical shares of Company Stock credited to each Participant's Company Stock Ledger shall continue to be recognized) and each Participant's benefits shall be paid in accordance with the otherwise applicable terms of the Plan. SECTION 11. EXECUTION IN WITNESS WHEREOF, the Company has caused this SCANA Corporation Director Compensation and Deferral Plan to be executed by its duly authorized officer this 5th day of December, 2000, to be effective as of January 1, 2001. SCANA Corporation By: s/W. B. Timmerman Title:CEO, Chairman of the Board ATTEST: s/Lynn M. Williams Secretary SCANA CORPORATION DIRECTOR COMPENSATION AND DEFERRAL PLAN ELECTION TO DEFER EXECUTED FOR CALENDAR YEAR _____ As a Participant in the SCANA Corporation Director Compensation and Deferral Plan (the "Plan"), I hereby make the elections set forth below. I understand and agree that all elections shall be subject to the terms of the Plan, a copy of which has been provided to me. I understand that elections under the Plan are voluntary and that the Company is not responsible for advising me with respect to the tax or financial consequences of my participation in this Plan. All capitalized terms have the meaning set forth in the Plan document. A. Deferral Election(s) or Election Not to Defer: [ ] 1. I do not wish to defer any amounts payable to me as a member of the Board of Directors during calendar year ________ . (Please complete Sections C and D below.) [ ] 2. I hereby elect to defer in accordance with this Plan one hundred percent (100%) of those amounts payable to me as a member of the Board of Directors during calendar year _____ including Retainer Fees, meeting attendance fees and conference fees and have those amounts credited to the Company Stock Ledger on my behalf. [ ] 3. I hereby elect to defer in accordance with this Plan those amounts payable to me as a member of the Board of Directors during calendar year _____ as follows (complete both a. and b.): [ ] a. I elect to defer ___ percent (up to forty percent (40%) of my Retainer Fees as well as ___ percent (up to one hundred percent (100%)) of my meeting attendance and conference fees. [ ] i. I elect that all such deferrals be credited to the Growth Increment Ledger on my behalf. [ ] ii. I elect that all such deferrals be credited to the Company Stock Ledger on my behalf. [ ] b. As to the remaining sixty percent (60%) of my Retainer Fees, I elect to defer all such Retainer Fees and have all such deferrals credited to the Company Stock Ledger on my behalf. B. Dividend Reinvestment Election (only complete if elected to have amounts credited to the Company Stock Ledger under Deferral Election above): [ ] a. I hereby elect that all amounts equal to dividends attributable to amounts credited to the Company Stock Ledger on my behalf shall be deemed to be reinvested in shares of Company Stock. [ ] b. I hereby elect that all amounts equal to dividends attributable to amounts credited to the Company Stock Ledger on my behalf shall be paid to me in cash. C. Compensation Election (only complete if not deferring one hundred percent (100%) of Compensation under the Deferral Election above): With respect to amounts not otherwise deferred under the Plan, I hereby elect to receive in accordance with this Plan those amounts payable to me as a member of the Board of Directors during calendar year ______ and payable as Retainer Fees (exclusive of the amounts otherwise required to be paid to me in shares of Company Stock), meeting attendance fees and conference fees in the form of: [ ] a. Company Stock [ ] b. Cash D. Investment Election (only complete if elected to receive Company Stock under Compensation Election above): [ ] a. I hereby elect that the shares of Company Stock to be issued to me during calendar year _____ be registered in my name. [ ] b. I hereby elect that the shares of Company Stock to be issued to me during calendar year ______ be deposited into an account in my name in the SCANA Investor Plus Plan. E. Deferral Period(s): Board of Directors' fees deferred above per this election shall be deferred (subject to an acceleration of payments under Section 6.4 of the Plan): [ ] a. ____ years from the close of the calendar year for which this election is made so as to be payable in whole or in part under the Manner of Payment Election indicated below as soon as practicable after January 1, -------. or [ ] b. until my departure from the Board of Directors as indicated in Section 4.2 of this Plan by reason of death, resignation or otherwise or the date I am no longer a Nonemployee Director. F. Manner of Payment Election(s): I understand and agree that, with respect to all deferred amounts, unless I elect otherwise, the amounts will be paid to me at the time otherwise specified in the form of a single lump sum payment. The Board of Directors fees deferred above per this election shall be paid (subject to an acceleration of payments under Section 6.4 of the Plan): [ ] a. in a lump sum, or [ ] b. in installment payments, payable: ------------- (Number) [ ] monthly or [ ] quarterly or [ ] annually. Name ________________________________ SS # ________________________________ - ----------------------------- ------------------------------------ Secretary, SCANA Corporation Board Member's Signature - ------------- ------------ Date Date (Rev. Jan. 2001) SCANA CORPORATION DIRECTOR COMPENSATION AND DEFERRAL PLAN DESIGNATION OF BENEFICIARY To: Secretary of SCANA Corporation I hereby designate the following person(s), trust(s) or estate, to be the recipient(s) of any and all amounts which may become payable or may remain to be paid upon my death under the SCANA Corporation Director Compensation and Deferral Plan. - -------------------------------------------------------------------------------- Beneficiary's Name and Social Security Beneficiary's Relationship Dollars or or Employer Address to % Share Identification No. Participant - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - --------------------------- --------------------------------------------------- I hereby designate the following person, trust or estate as Alternate Beneficiary with respect to the contingency events described in Sections 7.2(a) and 7.2(b) of this Plan. - ------------------------------------------------------------------------------- Alternate Beneficiary's Name and Social Alternate Relationship Security or Employer Beneficiary's to Identification No. Address Participant - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Spouse's Consent: (Community Property States Only-- S.C. domiciliaries ignore): - ---------------- I hereby agree to the Beneficiary(ies) designated above: - ----------------------------------- ------------------------ Spouse's Signature Date I hereby revoke any Beneficiary designation previously made by me and reserve the right to change this designation at any time by filing a new Designation of Beneficiary form. Signature of Participant ------------------------------------------------------- Date Social Security Number ---------------------- --------------------------- Signature of Corporate Secretary ----------------------------------------------- Date Received ------------------------------------------------------------------ (Rev. 2001) EX-31 8 exh31-1.txt CERTIFICATIONS Exhibit 31.1 CERTIFICATION I, William B. Timmerman, certify that: 1. I have reviewed this quarterly report on Form 10-Q of SCANA Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2003 s/William B. Timmerman William B. Timmerman Chairman of the Board, President, Chief Executive Officer and Director Exhibit 31.2 CERTIFICATION I, Kevin B. Marsh, certify that: 1. I have reviewed this quarterly report on Form 10-Q of SCANA Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2003 s/Kevin B. Marsh Kevin B. Marsh Senior Vice President and Chief Financial Officer Exhibit 31.3 CERTIFICATION I, William B. Timmerman, certify that: 1. I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2003 s/William B. Timmerman William B. Timmerman Chairman of the Board, Chief Executive Officer and Director Exhibit 31.4 CERTIFICATION I, Kevin B. Marsh, certify that: 1. I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2003 s/Kevin B. Marsh Kevin B. Marsh Senior Vice President and Chief Financial Officer Exhibit 31.5 CERTIFICATION I, William B. Timmerman, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Public Service Company of North Carolina, Incorporated; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2003 s/William B. Timmerman William B. Timmerman Chairman of the Board, Chief Executive Officer and Director Exhibit 31.6 CERTIFICATION I, Kevin B. Marsh, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Public Service Company of North Carolina, Incorporated; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2003 s/Kevin B. Marsh Kevin B. Marsh Senior Vice President and Chief Financial Officer EX-32 9 exh32-1.txt CERTIFICATIONS Exhibit 32.1 SCANA CORPORATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of SCANA Corporation (the "Company") on Form 10-Q for the quarter ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13 (a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 8, 2003 s/William B. Timmerman William B. Timmerman Chairman of the Board, President, Chief Executive Officer and Director A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32.2 SCANA CORPORATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of SCANA Corporation (the "Company") on Form 10-Q for the quarter ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 8, 2003 s/Kevin B. Marsh Kevin B. Marsh Senior Vice President and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32.3 SOUTH CAROLINA ELECTRIC AND GAS COMPANY CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of South Carolina Electric and Gas Company (the "Company") on Form 10-Q for the quarter ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 8, 2003 s/William B. Timmerman William B. Timmerman Chairman of the Board, Chief Executive Officer and Director A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32.4 SOUTH CAROLINA ELECTRIC AND GAS COMPANY CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of South Carolina Electric and Gas Company (the "Company") on Form 10-Q for the quarter ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 8, 2003 s/Kevin B. Marsh Kevin B. Marsh Senior Vice President and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32.5 PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Public Service Company of North Carolina, Incorporated (the "Company") on Form 10-Q for the quarter ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 8, 2003 s/William B. Timmerman William B. Timmerman Chairman of the Board, Chief Executive Officer and Director A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32.6 PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Public Service Company of North Carolina, Incorporated (the "Company") on Form 10-Q for the quarter ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 8, 2003 s/Kevin B. Marsh Kevin B. Marsh Senior Vice President and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----