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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2004

or

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from                                to                                 

       

Commission
File Number

  Registrant, State of Incorporation,
Address and Telephone Number

  I.R.S. Employer
Identification No.

1-8809   SCANA Corporation
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
  57-0784499

1-3375

 

South Carolina Electric & Gas Company
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000

 

57-0248695

1-11429

 

Public Service Company of North Carolina, Incorporated
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000

 

56-2128483

        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 ý No o South Carolina Electric & Gas Company Yes ý No o Public Service Company of North Carolina, Incorporated Yes ý No o.

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes ý No o South Carolina Electric & Gas Company Yes o No ý Public Service Company of North Carolina, Incorporated Yes o No ý.

        Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Registrant

  Description of
Common Stock

  Shares Outstanding at April 30, 2004
 
SCANA Corporation   Without Par Value   111,114,644  
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 March 31, 2004 and December 31, 2003   4
    Condensed Consolidated Statements of Income for the Periods Ended March 31, 2004 and 2003   6
    Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 2004 and 2003   7
    Condensed Consolidated Statements of Comprehensive Income for the Periods Ended March 31, 2004 and 2003   8
    Notes to Condensed Consolidated Financial Statements   9

Item 2.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

 

19

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

26

Item 4.

 

Controls and Procedures

 

27

South Carolina Electric & Gas Company Financial Section

 

28
Item 1.   Financial Statements    
    Condensed Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003   29
    Condensed Consolidated Statements of Income for the Periods Ended March 31, 2004 and 2003   31
    Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 2004 and 2003   32
    Notes to Condensed Consolidated Financial Statements   33

Item 2.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

 

40

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

46

Item 4.

 

Controls and Procedures

 

46

Public Service Company of North Carolina, Incorporated Financial Section

 

47
Item 1.   Financial Statements    
    Condensed Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003   48
    Condensed Consolidated Statements of Income for the Periods Ended March 31, 2004 and 2003   49
    Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 2004 and 2003   50
    Notes to Condensed Consolidated Financial Statements   51

Item 2.

 

Management's Narrative Analysis of Results of Operations

 

54

Item 4.

 

Controls and Procedures

 

55

PART II. OTHER INFORMATION

 

 

Item 1.

 

Legal Proceedings

 

56

Item 2.

 

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

 

56

Item 6.

 

Exhibits and Reports on Form 8-K

 

56

Signatures

 

58

Exhibit Index

 

59

2



SCANA CORPORATION
FINANCIAL SECTION

3



PART I. FINANCIAL INFORMATION


Item 1. Financial Statements

SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

Millions of dollars

  March 31,
2004

  December 31,
2003

 
Assets              
Utility Plant:              
  Electric   $ 5,616   $ 5,558  
  Gas     1,691     1,687  
  Common     196     193  
   
 
 
  Total     7,503     7,438  
  Accumulated depreciation and amortization     (2,316 )   (2,280 )
   
 
 
  Total     5,187     5,158  
  Construction work in progress     1,035     987  
  Nuclear fuel, net of accumulated amortization     36     42  
  Acquisition adjustments, net of accumulated amortization     230     230  
   
 
 
  Utility Plant, Net     6,488     6,417  
   
 
 
Nonutility Property, Net of Accumulated Depreciation     93     96  
Investments     168     178  
   
 
 
  Nonutility Property and Investments, Net     261     274  
   
 
 
Current Assets:              
  Cash and temporary investments     218     117  
  Receivables, net of allowance for uncollectible accounts of $23 and $16     494     503  
  Receivables—affiliated companies     18     13  
  Inventories (at average cost):              
    Fuel     94     147  
    Materials and supplies     62     60  
    Emission allowances     13     6  
  Prepayments     41     36  
  Deferred income taxes, net     12      
   
 
 
  Total Current Assets     952     882  
   
 
 
Deferred Debits:              
  Environmental     19     20  
  Assets held in trust, net—nuclear decommissioning     46     44  
  Pension asset, net     274     270  
  Other regulatory assets     328     348  
  Other     181     175  
   
 
 
  Total Deferred Debits     848     857  
   
 
 
Total   $ 8,549   $ 8,430  
   
 
 

4


Millions of dollars

  March 31,
2004

  December 31,
2003

Capitalization and Liabilities            
Shareholders' Investment:            
  Common equity   $ 2,370   $ 2,306
  Preferred stock (Not subject to purchase or sinking funds)     106     106
   
 
  Total Shareholders' Investment     2,476     2,412
Preferred Stock, net (Subject to purchase or sinking funds)     9     9
Long-Term Debt, net     3,332     3,225
   
 
  Total Capitalization     5,817     5,646
   
 
Current Liabilities:            
  Short-term borrowings     191     195
  Current portion of long-term debt     202     202
  Accounts payable     238     288
  Accounts payable—affiliated companies     16     12
  Customer deposits     45     43
  Taxes accrued     51     81
  Interest accrued     57     55
  Dividends declared     43     41
  Deferred income taxes, net         4
  Other     49     74
   
 
  Total Current Liabilities     892     995
   
 
Deferred Credits:            
  Deferred income taxes, net     802     790
  Deferred investment tax credits     116     117
  Asset retirement obligation—nuclear plant     119     118
  Postretirement benefits     136     135
  Other regulatory liabilities     549     519
  Other     118     110
   
 
  Total Deferred Credits     1,840     1,789
   
 
Commitments and Contingencies        
   
 
Total   $ 8,549   $ 8,430
   
 

See Notes to Condensed Consolidated Financial Statements.

5



SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

 
  Three Months Ended
March 31,

Millions of dollars, except per share amounts

  2004
  2003
Operating Revenues:            
  Electric   $ 380   $ 336
  Gas—regulated     426     427
  Gas—nonregulated     330     306
   
 
  Total Operating Revenues     1,136     1,069
   
 
Operating Expenses:            
  Fuel used in electric generation     95     81
  Purchased power     13     10
  Gas purchased for resale     577     571
  Other operation and maintenance     155     144
  Depreciation and amortization     63     60
  Other taxes     39     35
   
 
  Total Operating Expenses     942     901
   
 
Operating Income     194     168

Other Income, Including Allowance for Equity Funds Used During Construction of $6 and $5

 

 

14

 

 

16
   
 
Income Before Interest Charges, Income Taxes and Preferred Stock Dividends     208     184
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $4 and $2     50     51
Dividend Requirement of SCE&G—Obligated Mandatorily Redeemable Preferred Securities         1
   
 
Income Before Income Taxes and Preferred Stock Dividends     158     132
Income Tax Expense     55     46
   
 
Income Before Preferred Stock Dividends     103     86
Cash Dividends on Preferred Stock of Subsidiary (At stated rates)     2     2
   
 
Net Income   $ 101   $ 84
   
 
Basic and Diluted Earnings Per Share of Common Stock   $ .91   $ .75
Weighted Average Shares Outstanding (millions)     110.9     110.8

See Notes to Condensed Consolidated Financial Statements.

6


SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
  Three Months Ended
March 31,

 
Millions of dollars

 
  2004
  2003
 
Cash Flows From Operating Activities:              
  Net income   $ 101   $ 84  
  Adjustments to reconcile net income to net cash provided from operating activities:              
    Depreciation and amortization     64     62  
    Amortization of nuclear fuel     6     6  
    Loss on sale of assets     1      
    Hedging activities     (3 )   (3 )
    Allowance for funds used during construction     (10 )   (7 )
    Over collection, fuel adjustment clauses     42     16  
    Changes in certain assets and liabilities:              
      (Increase) decrease in receivables, net     4     (38 )
      (Increase) decrease in inventories     44     62  
      (Increase) decrease in prepayments     (5 )    
      (Increase) decrease in pension asset     (4 )   (1 )
      (Increase) decrease in other regulatory assets     1     (1 )
      Increase (decrease) in deferred income taxes, net     1     1  
      Increase (decrease) in regulatory liabilities     3     9  
      Increase (decrease) in postretirement benefits obligations     1     3  
      Increase (decrease) in accounts payable     (46 )   10  
      Increase (decrease) in taxes accrued     (30 )   (24 )
      Increase (decrease) in interest accrued     2     6  
    Changes in other assets     4     (10 )
    Changes in other liabilities     (13 )   (20 )
   
 
 
  Net Cash Provided From Operating Activities     163     155  
   
 
 
Cash Flows From Investing Activities:              
  Utility property additions and construction expenditures, net of AFC     (122 )   (171 )
  Increase in nonutility property     (4 )   (3 )
  Investments in affiliates     (3 )   (4 )
   
 
 
  Net Cash Used For Investing Activities     (129 )   (178 )
   
 
 
Cash Flows From Financing Activities:              
  Proceeds:              
    Issuance of First Mortgage Bonds         198  
    Issuance of notes and loans     100      
    Issuance of common stock upon exercise of stock options     15      
  Repayments:              
    Notes and loans         (60 )
    Repurchase of common stock     (4 )    
  Dividends and distributions:              
    Common stock     (38 )   (37 )
    Preferred stock     (2 )   (2 )
  Short-term borrowings, net     (4 )   (95 )
   
 
 
  Net Cash Provided From Financing Activities     67     4  
   
 
 
Net Increase (Decrease) In Cash and Temporary Investments     101     (19 )
Cash and Temporary Investments, January 1     117     341  
   
 
 
Cash and Temporary Investments, March 31   $ 218   $ 322  
   
 
 
Supplemental Cash Flow Information:              
  Cash paid for—Interest (net of capitalized interest of $4 and $2)   $ 47   $ 46  
                        —Income taxes         1  

Noncash Investing and Financing Activities:

 

 

 

 

 

 

 
  Unrealized loss on securities available for sale, net of tax     (6 )    

See Notes to Condensed Consolidated Financial Statements.

7


SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

 
  Three Months Ended
March 31,

 
Millions of dollars

 
  2004
  2003
 
Net Income   $ 101   $ 84  
Other Comprehensive Income (Loss), net of tax:              
  Unrealized losses on securities available for sale     (6 )    
  Unrealized losses on hedging activities     (2 )   (2 )
   
 
 
Total Comprehensive Income(1)   $ 93   $ 82  
   
 
 

(1)
Accumulated other comprehensive income (loss) totaled $(2.1) million and $5.6 million as of March 31, 2004 and December 31, 2003, respectively.

See Notes to Condensed Consolidated Financial Statements.

8


SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)

        The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2003. 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 certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded as of March 31, 2004, approximately $347 million and $549 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

Millions of dollars

  March 31,
2004

  December 31,
2003

 
Accumulated deferred income taxes, net   $ 109   $ 110  
Under-(over)-collections—electric fuel and gas cost adjustment clauses, net     (1 )   38  
Deferred environmental remediation costs     19     20  
Asset retirement obligation—nuclear decommissioning     47     48  
Deferred non-conventional fuel tax benefits, net     (74 )   (67 )
Storm damage reserve     (34 )   (37 )
Franchise agreements     60     62  
Non-legal asset retirement obligations     (353 )   (346 )
Other     25     21  
   
 
 
Total   $ (202 ) $ (151 )
   
 
 

        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-(over-) collections—fuel adjustment clauses, net represent amounts under or over-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. Such costs, totaling approximately $9.8 million, are expected to be fully recovered by the end of 2009. A portion of the costs incurred at sites owned by PSNC Energy has been recovered

9



through rates, and management believes the remaining costs of approximately $6.8 million will be recoverable. Amounts incurred and deferred to date that are not currently being recovered through gas rates at PSNC Energy are approximately $2.4 million.

        Asset retirement obligation—nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required by SFAS 143, "Accounting for Asset Retirement Obligations."

        Deferred non-conventional fuel tax benefits, net represent the deferral of partnership losses and other expenses of approximately $44 million, offset by the accumulated deferred income tax credits of approximately $117 million associated with SCE&G's two partnerships involved in converting coal to synthetic fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced by the partnerships 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 period of approximately ten years. The accumulated storm damage reserve can be applied to offset actual incremental 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 approximately 15 years.

        Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.

        The SCPSC and the NCUC (collectively, state commissions) 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 a state commission. 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 state commission 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, liquidity or financial position in the period the write-off would be recorded.

B.    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 SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure."

        All options have been granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates since the Plan's inception; therefore, no compensation expense has been recognized in connection with such grants. If the Company had determined to recognize

10



compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings per share would have been as presented below:

 
  Three Months Ended
March 31,

 
  2004
  2003
Net income—as reported (millions)   $ 101.2   $ 83.6
Net income—pro forma (millions)   $ 100.9   $ 83.2
Basic and diluted earnings per share—as reported   $ .91   $ .75
Basic and diluted earnings per share—pro forma   $ .91   $ .75

        No options have been granted since 2002.

C.    Pension and Other Postretirement Benefit Plans

        Components of net periodic benefit income or cost recorded by the Company were as follows:

 
   
   
  Other Postretirement Benefits
 
  Pension Benefits
Three months ended March 31 (Millions of dollars)

  2004
  2003
  2004
  2003
Service cost   $ 2.8   $ 2.6   $ 0.8   $ 1.3
Interest cost     9.1     9.5     2.9     3.8
Expected return on assets     (17.7 )   (15.0 )      
Prior service cost amortization     1.6     1.6     0.2     0.8
Transition obligation amortization     0.2     0.2     0.3     0.3
Actuarial (gain) loss         0.5     0.5     0.2
   
 
 
 
Net periodic benefit (income) cost   $ (4.0 ) $ (0.6 ) $ 4.7   $ 6.4
   
 
 
 

D.    Earnings Per Share

        Earnings per share amounts have been computed in accordance with SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed as net income divided by the weighted average number of shares of common stock outstanding during the period after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock.

E.    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 these affiliated companies approximately $17.8 million and $13.4 million at March 31, 2004 and December 31, 2003, respectively. SCE&G had recorded as payables to these affiliated companies approximately $15.6 million and $12.2 million at March 31, 2004 and December 31, 2003, respectively.

F.     Reclassifications

        Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2004.

11



2.     RATE AND OTHER REGULATORY MATTERS

        In January 2003, in conjunction with the approval of a retail rate increase, the SCPSC deferred action on the recovery of certain purchased power costs pending the resolution of the appeal of the SCPSC's May 2002 order. In May 2002 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers, which reflected 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 Consumer Advocate of South Carolina (Consumer Advocate) 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 Circuit Court ruled that the current fuel clause only provides for the recovery of the fuel costs included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the portion of the purchased power costs not allowed to be recovered through the fuel clause.

        In April 2004 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.678 cents per KWh to 1.821 cents per KWh. The increase reflects higher fuel costs projected for the period May 2004 through April 2005. The increase also provides continued recovery for under-collected actual fuel costs through February 2004. The new rates will be effective as of the first billing cycle in May 2004.

        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, 2003 through March 31, 2004 was as follows:

Rate Per Therm

  Effective Date
$ .728   January–February 2003
  .928   March–October 2003
  .877   November 2003–March 2004

        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 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce the billing surcharge from 3.0 cents per therm to 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at March 31, 2004 of $9.8 million.

        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

12


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, 2003 through March 31, 2004 was as follows:

Rate Per Therm

  Effective Date
$ .460   January–February 2003
  .595   March 2003
  .725   April–November 2003
  .600   December 2003–March 2004

        For service rendered on and after March 1, 2004, the NCUC authorized PSNC Energy to implement decrements in its sales and transportation rate schedules to reflect a decrease of approximately $5.7 million in PSNC Energy's annual fixed gas costs as well as the current over-recovery of approximately $16.5 million.

        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 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion was completed and placed in service in April 2004. Through March 31, 2004 approximately $29 million had been spent on this project.

        In December 1999 the NCUC issued an order approving the Company'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.

3.     LONG-TERM DEBT

        On February 11, 2004 South Carolina Generating Company, Inc. (GENCO) issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.

4.     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 March 31, 2004 approximately $45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

5.     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,"

13



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. The Company also holds investments in several partnerships and joint ventures, some of which are accounted for using the equity method.

        At March 31, 2004 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held investments in the following equity and debt securities.

Investee

  Securities
  Basis
 
   
  (Millions of dollars)


Magnolia Holding

 

6.2 million shares nonvoting common stock

 

$

2.1

ITC^DeltaCom

 

567.5 thousand shares of common stock

 

 

1.1
    163.6 thousand shares series A 8% preferred stock, convertible into 2.8 million shares of common stock     13.2
    Warrants to purchase 506.9 thousand shares of common stock     1.1

Knology

 

2.6 million shares of common stock

 

 

23.1
    2.2 million shares of nonvoting common stock     19.6
    13% senior unsecured notes due 2009, including accrued interest     51.1
    Warrants to purchase 16.5 thousand shares of common stock    

        Magnolia Holding Company, LLC (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 had a market value of $3.7 million, and the warrants owned have a market value of $2.0 million as of March 31, 2004. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and their market value is not readily determinable.

        Knology, Inc. (Knology) is a fully integrated provider of video, voice, data and advanced communication services to residential and business customers in the southeastern United States. The common shares of Knology (voting and non-voting) owned by SCH had a market value of $32.6 million as of March 31, 2004.

Derivatives

        The Company follows the guidance required by FAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 9 to the consolidated financial statements in the Company's 2003 Form 10-K.

        The Company recognized gains of approximately $1.9 million and $5.6 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three months

14



ended March 31, 2004 and 2003, respectively. These amounts were recorded in cost of gas. The Company estimates that most of the March 31, 2004 unrealized gain balance of $3.2 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 March 31, 2004, all of the Company's cash flow hedges settle by their terms before the end of 2006.

        Option premiums and gains resulting from qualifying fair value hedges during the three months ended March 31, 2004 and 2003 were insignificant and were recorded in cost of gas. As of March 31, 2004 all of the Company's fair value hedges had settled.

        At March 31, 2004 the estimated fair value of the Company's swaps totaled $14.3 million (gain) related to combined notional amounts of $333.1 million.

6.     COMMITMENTS AND CONTINGENCIES

        Reference is made to Note 10 to the consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2003. Commitments and contingencies at March 31, 2004 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. 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 March 31, 2004 totaled approximately $192 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 $10.8 billion. Each reactor licensee is currently liable for up to $100.6 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 $67.1 million per incident, but not more than $6.7 million per year.

        Congress failed to renew the Price-Anderson Indemnification Act when it expired in 2003. The delayed renewal has no impact on the Company due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.

        SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $15.8 million.

15


        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 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 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 $9.8 million at March 31, 2004. 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 by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of March 31, 2004, SCE&G has spent approximately $19.8 million to remediate the Calhoun Park site and expects to spend an additional $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 the South Carolina Department of Health and Environmental Control (DHEC). SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of March 31, 2004, SCE&G has spent approximately $3.1 million related to these sites, and expects to spend an additional $4.9 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 $6.8 million, which reflects the estimated remaining liability at March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.4 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.

D.    Claims and Litigation

        In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of SCANA Corporation (SCANA) filed suit against SCANA in Circuit Court, seeking unspecified damages. The

16



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 does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position.

        On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. 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.

        A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint also alleges that SCE&G failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are the subject of a similar lawsuit that was filed and served on SCE&G, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and SCE&G. SCE&G believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.

        The Company is 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.

7.     SEGMENT OF BUSINESS INFORMATION

        The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its 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. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation.

17



Disclosure of Reportable Segments
(Millions of dollars)

Three Months Ended
March 31, 2004

  External
Revenue

  Intersegment
Revenue

  Operating
Income

  Net
Income

  Segment
Assets

Electric Operations   $ 380   $ 1   $ 96     n/a   $ 5,134
Gas Distribution     370     2     58     n/a     1,449
Gas Transmission     54     118     6     n/a     313
Retail Gas Marketing     218         n/a   $ 20     145
Energy Marketing     112     3     n/a         51
All Other     15     68     1     1     684
Adjustments/Eliminations     (13 )   (192 )   33     80     773
   
 
 
 
 
Consolidated Total   $ 1,136   $   $ 194   $ 101   $ 8,549
   
 
 
 
 
March 31, 2003

   
   
   
   
   
Electric Operations   $ 336   $ 2   $ 84     n/a   $ 4,566
Gas Distribution     343         61     n/a     1,416
Gas Transmission     84     108     5     n/a     317
Retail Gas Marketing     183         n/a   $ 13     124
Energy Marketing     123         n/a     (2 )   67
All Other     14     67         (1 )   601
Adjustments/Eliminations     (14 )   (177 )   18     74     1,086
   
 
 
 
 
Consolidated Total   $ 1,069   $   $ 168   $ 84   $ 8,177
   
 
 
 
 

18



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 (together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2003.

        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, including competition from alternate fuels in industrial interruptible markets, (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. The Company disclaims any obligation to update any forward-looking statements.

Electric Operations

        In April 2004 the joint U.S.-Canada Power System Outage Task Force issued its "Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report). The Blackout Report contains 46 recommendations that, if implemented, the Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the Blackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed the House and Senate in 2003 but have stalled in conference committee. Various provisions of the Energy Bill related to electric reliability are being resubmitted as separate legislation (reliability legislation). It is anticipated that any reliability legislation, if passed, would make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the U.S. Federal Energy Regulatory Commission (FERC), enabling it to enact regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could have a significant

19



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 of its service territory.

        In addition, the North American Electric Reliability Council (NERC) is expected to proceed with its initiatives to develop, establish and enforce standards for the grid. To that end, NERC is working closely with FERC to implement stronger reliability standards among NERC's voluntary membership. SCE&G, along with other NERC members, is also working closely with NERC in these efforts. Such initiatives would be significantly influenced by any reliability legislation enacted by Congress. If implemented, such initiatives by FERC and NERC could 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.

Retail Gas Marketing

        In March 2004 SCANA Energy acquired approximately 47,000 retail natural gas customers formerly served by another gas marketer in Georgia. With this transaction, SCANA Energy's total customer base represents about a 30 percent share of the 1.5 million customers in Georgia's natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

        In March 2004 SCANA Energy's term for serving low-income and high credit risk customers was extended by the GPSC for an additional year (beginning September 1).

        In November 2003 the Georgia Public Service Commission (GPSC) filed a petition with FERC seeking a declaratory order on the assignment of interstate capacity. That petition addressed the question of whether FERC would preempt the GPSC if a plan proposed by SCANA Energy for the assignment of Atlanta Gas Light Company's interstate capacity assets to certificated natural gas marketers was adopted by the GPSC. On April 15, 2004 FERC ruled that it continues to maintain jurisdiction and would preempt the GPSC in any plan dealing with interstate capacity assets. SCANA Energy has operated successfully under the current interstate capacity plan and does not expect that FERC's ruling will have any negative impact on operations.

RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2004
AS COMPARED TO THE CORRESPONDING PERIOD IN 2003

Earnings Per Share

        Reported (GAAP) earnings per share of common stock for the periods ended March 31, 2004 and 2003 were as follows:

 
  First Quarter
 
  2004
  2003
Reported (GAAP) earnings per share   $ .91   $ .75
   
 

        Reported (GAAP) earnings per share increased by $.16 due to improved electric margins of $.15, improved gas margins of $.09, lower interest expense of $.01 and a reduction of preferred dividend requirements of $.01. These factors were partially offset by higher operation and maintenance expenses of $.06, higher property taxes of $.02 and higher depreciation and amortization expense of $.02.

20



Pension Income

        Pension income was recorded on the Company's financial statements as follows:

 
  First Quarter
 
Millions of dollars

 
  2004
  2003
 
Income Statement Impact:              
  Reduction in (component of) employee benefit costs   $ 1.1   $ (1.0 )
  Other income     2.5     1.9  
Balance Sheet Impact:              
Reduction in (component of) capital expenditures     0.3     (0.3 )
  Component of amount due to Summer Station co-owner     0.1      
   
 
 
Total Pension Income   $ 4.0   $ 0.6  
   
 
 

        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 in the first quarter of 2004 increased compared to the corresponding period in 2003 primarily as a result of a more favorable investment market.

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 increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project 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 2004:

Declaration Date

  Dividend Per Share
  Record Date
  Payment Date
February 19, 2004   $ .365   March 10, 2004   April 1, 2004
April 29, 2004   $ .365   June 10, 2004   July 1, 2004

Electric Operations

        Electric Operations is comprised of the electric operations of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company). Electric operations sales margins were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating revenues   $ 379.9   13.1 % $ 336.0
Less: Fuel used in generation     95.4   18.1 %   80.8
Purchased power     12.7   21.0 %   10.5
   
 
 
Margin   $ 271.8   11.1 % $ 244.7
   
 
 

21


        Margin increased primarily due to increased retail electric base rates that went into effect in February 2003, for a total impact of $7.1 million, an additional $3.2 million due to favorable weather, $14.6 million from off-system sales and $2.2 million due to customer growth and consumption.

Gas Distribution

        Gas Distribution is comprised of the local distribution operations of SCE&G and Public Service Company of North Carolina, Incorporated (PSNC Energy). Gas distribution sales margins (including transactions with affiliates) were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating revenues   $ 371.7   8.3 % $ 343.3
Less: Gas purchased for resale     264.2   14.1 %   231.5
   
 
 
Margin   $ 107.5   (3.9 )% $ 111.8
   
 
 

        Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and maintenance) and an unfavorable competitive position of natural gas relative to alternate fuels of $1.6 million, partially offset by customer growth and increased consumption of $0.5 million.

Gas Transmission

        Gas Transmission is comprised of the operations of South Carolina Pipeline Corporation (SCPC). Gas transmission sales margins (including transactions with affiliates) were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating revenues   $ 172.3   (10.5 )% $ 192.4
Less: Gas purchased for resale     157.7   (12.1 )%   179.4
   
 
 
Margin   $ 14.6   12.3 % $ 13.0
   
 
 

        Margin increased primarily due to higher transportation revenue as a result of new customers of $1.8 million, partially offset by an unfavorable competitive position of natural gas relative to alternate fuels of $0.5 million.

Retail Gas Marketing

        Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's natural gas market. Retail Gas Marketing revenues and net income were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating revenues   $ 217.7   18.5 % $ 183.7
Net income   $ 20.6   55.8 % $ 13.2

        Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $8.9 million partially offset by increased bad debt expense of $1.2 million.

22



Energy Marketing

        Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net loss were as follows:

 
  First Quarter
 
Millions of dollars

  2004
  % Change
  2003
 
Operating revenues   $ 115.2   (6.0 )% $ 122.4  
Net loss   $ (0.5 ) 74.6 % $ (1.8 )

        Operating revenues decreased primarily as a result of decreased volumes. Net loss decreased primarily due to improved gas margins of $1.7 million.

Other Operating Expenses

        Other operating expenses were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Other operation and maintenance   $ 154.6   7.3 % $ 144.1
Depreciation and amortization     62.7   4.7 %   59.9
Other taxes     38.8   12.5 %   34.5
   
 
 
Total   $ 256.1   7.4 % $ 238.5
   
 
 

23


        Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $5.8 million, increased bad debt expenses of $2.0 million, 2004 winter storm restoration expenses of $2.5 million and increased expense at electric generation plants of $3.4 million, partially offset by decreased recovery of environmental remediation expenses of $3.2 million (offset in gas margin) and increased pension income of $2.1 million. Depreciation and amortization increased due to normal net property changes. Other taxes increased primarily due to increased property taxes.

Other Income (Expense)

        Other income, including AFC, decreased primarily due to reduced other non-operating income partially offset by an increase in AFC due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project.

Income Taxes

        Income taxes increased primarily as a result of changes in operating income.

LIQUIDITY AND CAPITAL RESOURCES

        The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short-term and long-term indebtedness and sales of additional equity securities. 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 March 31, 2004 was 2.95.

        Cash requirements for the Company's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA Corporation. 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.

        The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the three months ended March 31, 2004 and 2003:

 
  Three Months Ended
March 31,

 
Millions of dollars

 
  2004
  2003
 
Net cash provided from operating activities   $ 163   $ 155  
Net cash provided from financing activities     67     4  
Cash and temporary investments available at the beginning of the period     117     341  

Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction

 

$

122

 

$

171

 
Funds used for nonutility property additions     4     3  
Funds used for investments     (3 )   (4 )

        SCE&G intends to file an electric rate case with the SCPSC in the summer of 2004 requesting, among other things, recovery of capital expenditures related to the generating facility in Jasper County, South Carolina. This filing will also include SCE&G's plan to use synthetic fuel tax credits to offset

24



construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the filing within six months of the rate application being filed.

CAPITAL TRANSACTIONS

        On February 11, 2004 GENCO issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.

        Effective May 1, 2004 shares of SCANA's common stock purchased on behalf of participants in the SCANA Investor Plus Plan, Stock Purchase-Savings Plan and Director Compensation and Deferral Plan are being purchased directly from SCANA rather than on the open market. SCANA estimates that these original issue purchases will result in the issuance of approximately 2 million new shares of common stock and provide approximately $65 million in additional common stock equity on an annual basis. In addition, effective April 29, 2004 SCANA discontinued purchasing outstanding shares of common stock on the open market.

CAPITAL PROJECTS

        Construction of SCE&G's 875 megawatt generation facility in Jasper County, South Carolina has been completed. The facility includes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility began commercial operation in May 2004. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder are expected to be included in the rate case previously discussed.

        In October 1999 FERC mandated that SCE&G reinforce its Lake Murray Dam in order to comply with new federal safety standards. 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 March 31, 2004 totaled approximately $192 million.

        Construction of SCPC's South System Loop was completed in March 2004 at a cost of approximately $21 million. This pipeline stretches 38.3 miles from SCG Pipeline's connection with SCE&G's Jasper County generation facility to Yemassee in Hampton County, South Carolina, providing a new supply source to SCPC's current system.

ENVIRONMENTAL MATTERS

        For information on environmental matters see Note 6C to condensed consolidated financial statements.

OTHER MATTERS

Nuclear Station

        In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through 2042.

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 March 31, 2004 is approximately $3 million, and through March 31, 2004, they have generated and passed through to SCE&G approximately $107 million in such tax credits. At March 31, 2004 SCE&G has recorded on its balance sheet $74 million net deferred

25



fuel tax benefits, which include partnership losses, net of tax. 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 to SCE&G from synfuel produced for 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 to the condensed consolidated financial statements.

        In March 2004 the Company received a "No Change" letter from the Internal Revenue Service (IRS) related to SCE&G's interest in the synthetic fuel partnership S. C. Coaltech No. l L.P. for the tax year 2000. This letter supports the Company's position that the synthetic fuel tax credits have been properly claimed.


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 March 31, 2004
  Expected Maturity Date
Millions of dollars
Liabilities

  2004
  2005
  2006
  2007
  2008
  There-
After

  Total
  Fair
Value

Long-Term Debt:                                
Fixed Rate ($)   197.9   193.6   174.4   68.6   158.6   2,640.9   3,434.0   3,484.1
Average Fixed Interest Rate (%)   7.53   7.39   8.50   6.96   6.13   6.24   6.60    
Variable Rate ($)           200.0               200.0   200.0
Average Variable Interest Rate (%)           1.57               1.57    

Interest Rate Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Pay Variable/Receive Fixed ($)   57.5   3.2   3.2   28.2   118.2   122.8   333.1   14.3
  Average Pay Interest Rate (%)   5.84   4.30   4.30   4.31   2.81   2.97   3.55    
  Average Receive Interest Rate (%)   7.70   8.75   8.75   7.11   5.89   6.51   6.59    

        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 March 31, 2004 the Company held investments in the 13% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $51.1 million. As these notes are not broadly 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.

26



Expected Maturity:

 
  Futures Contracts
   
  Options
2004

  Long ($)
  Short ($)
   
  Purchased call
(long) ($)

  Purchased put
(short) ($)

Settlement Price(a)   6.05   6.01            
Contract Amount   16.5   2.4   Strike Price(a)   4.86  
Fair Value   20.0   2.6   Contract Amount   6.8  

2005


 

 


 

 


 

 


 

 


 

 

Settlement Price(a)   5.89   6.44            
Contract Amount   5.3   0.2   Strike Price(a)    
Fair Value   6.5   0.2   Contract Amount    

2006


 

 


 

 


 

 


 

 


 

 

Settlement Price(a)   5.66              
Contract Amount   0.5     Strike Price(a)    
Fair Value   0.7     Contract Amount    

(a)
Weighted average

        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 $40.4 million at March 31, 2004. A temporary decline in value of ten percent would result in a $4.0 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 $4.0 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.


Item 4. Controls and Procedures

        As of March 31, 2004 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 March 31, 2004 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 March 31, 2004 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.

27




SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION

28



Item 1.    Financial Statements

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

Millions of dollars

  March 31,
2004

  December 31,
2003

 
Assets              
Utility Plant:              
  Electric   $ 5,616   $ 5,558  
  Gas     459     456  
  Common     196     193  
   
 
 
  Total     6,271     6,207  
  Accumulated depreciation and amortization     (1,937 )   (1,907 )
   
 
 
  Total     4,334     4,300  
  Construction work in progress     989     951  
  Nuclear fuel, net of accumulated amortization     36     42  
   
 
 
  Utility Plant, Net     5,359     5,293  
   
 
 
Nonutility Property and Investments, Net     26     25  
   
 
 
Current Assets:              
  Cash and temporary investments     79     56  
  Receivables, net     230     238  
  Receivables—affiliated companies     42     61  
  Inventories (at average cost):              
    Fuel     30     35  
    Materials and supplies     56     54  
    Emission allowances     13     6  
  Prepayments     25     20  
  Deferred income taxes, net     4      
   
 
 
  Total Current Assets     479     470  
   
 
 
Deferred Debits:              
  Environmental     10     11  
  Assets held in trust, net—nuclear decommissioning     46     44  
  Pension asset, net     274     270  
  Due from affiliates—pension and postretirement benefits     21     20  
  Other regulatory assets     310     333  
  Other     139     145  
   
 
 
  Total Deferred Debits     800     823  
   
 
 
Total   $ 6,664   $ 6,611  
   
 
 

29


Millions of dollars

  March 31,
2004

  December 31,
2003

Capitalization and Liabilities            
Shareholders' Investment:            
  Common equity   $ 2,059   $ 2,043
  Preferred stock (Not subject to purchase or sinking funds)     106     106
   
 
  Total Shareholders' Investment     2,165     2,149
Preferred Stock, net (Subject to purchase or sinking funds)     9     9
Long-Term Debt, net     2,110     2,010
   
 
Total Capitalization     4,284     4,168
   
 
Minority Interest     75     100
   
 
Current Liabilities:            
  Short-term borrowings     191     140
  Current portion of long-term debt     142     142
  Accounts payable     93     104
  Accounts payable—affiliated companies     91     134
  Customer deposits     25     25
  Taxes accrued     48     101
  Interest accrued     40     39
  Dividends declared     38     43
  Deferred income taxes, net         8
  Other     24     34
   
 
  Total Current Liabilities     692     770
   
 
Deferred Credits:            
  Deferred income taxes, net     720     707
  Deferred investment tax credits     114     114
  Asset retirement obligation—nuclear plant     119     118
  Due to affiliates—pension and postretirement benefits     15     15
  Postretirement benefits     136     135
  Regulatory liabilities     446     429
  Other     63     55
   
 
  Total Deferred Credits     1,613     1,573
   
 
Commitments and Contingencies        
   
 
Total   $ 6,664   $ 6,611
   
 

See Notes to Condensed Consolidated Financial Statements.

30



SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

 
  Three Months Ended
March 31,

Millions of dollars

  2004
  2003
Operating Revenues:            
  Electric   $ 381   $ 337
  Gas     146     140
   
 
  Total Operating Revenues     527     477
   
 
Operating Expenses:            
  Fuel used in electric generation     95     81
  Purchased power (including affiliated purchases)     13     10
  Gas purchased for resale     111     100
  Other operation and maintenance     108     104
  Depreciation and amortization     52     49
  Other taxes     35     31
   
 
  Total Operating Expenses     414     375
   
 
Operating Income     113     102
Other Income, Including Allowance for Equity Funds Used During Construction of $5 and $4     6     7
   
 
Income Before Interest Charges, Minority Interest, Income Taxes and Preferred Stock Dividends     119     109
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $3 and $2     35     34
Dividend Requirement of Company—Obligated Mandatorily Redeemable Preferred Securities         1
   
 
Income Before Minority Interest, Income Taxes and Preferred Stock Dividends     84     74
Minority Interest     2     2
   
 
Income Before Income Taxes and Preferred Stock Dividends     82     72
Income Tax Expense     28     25
   
 
Net Income     54     47
Preferred Stock Cash Dividends Declared (At stated rates)     2     2
   
 
Earnings Available for Common Shareholder   $ 52   $ 45
   
 

See Notes to Condensed Consolidated Financial Statements.

31



SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
  Three Months Ended
March 31,

 
Millions of dollars

 
  2004
  2003
 
Cash Flows From Operating Activities:              
  Net income   $ 54   $ 47  
  Adjustments to reconcile net income to net cash provided from operating activities:              
    Minority interest     2     2  
    Depreciation and amortization     52     49  
    Amortization of nuclear fuel     6     6  
    Allowance for funds used during construction     (8 )   (6 )
    Over collections, fuel adjustment clauses     32     22  
    Changes in certain assets and liabilities:              
      (Increase) decrease in receivables, net     27     (1 )
      (Increase) decrease in inventories     (4 )   15  
      (Increase) decrease in prepayments     (5 )   3  
      (Increase) decrease in pension asset     (4 )   (1 )
      (Increase) decrease in other regulatory assets     2      
      Increase (decrease) in deferred income taxes, net     1     (1 )
      Increase (decrease) in regulatory liabilities     4     9  
      Increase (decrease) in postretirement benefits obligations     1     3  
      Increase (decrease) in accounts payable     (54 )   (22 )
      Increase (decrease) in taxes accrued     (53 )   (41 )
      Increase (decrease) in interest accrued     1     5  
    Changes in other assets     (1 )   (21 )
    Changes in other liabilities         (2 )
   
 
 
  Net Cash Provided From Operating Activities     53     66  
   
 
 
Cash Flows From Investing Activities:              
  Utility property additions and construction expenditures, net of AFC     (107 )   (155 )
  Increase in nonutility property     (1 )    
  Investments in affiliates     (3 )   (4 )
   
 
 
  Net Cash Used For Investing Activities     (111 )   (159 )
   
 
 
Cash Flows From Financing Activities:              
  Proceeds:              
    Issuance of First Mortgage Bonds         198  
    Issuance of notes     100      
  Dividends and distributions:              
    Common stock     (41 )   (40 )
    Preferred stock     (2 )   (2 )
    Distribution to parent     (27 )    
  Short-term borrowings, net     51     (64 )
   
 
 
  Net Cash Provided From Financing Activities     81     92  
   
 
 
Net Increase (Decrease) In Cash and Temporary Investments     23     (1 )
Cash and Temporary Investments, January 1     56     23  
   
 
 
Cash and Temporary Investments, March 31   $ 79   $ 22  
   
 
 
Supplemental Cash Flow Information:              
  Cash paid for—Interest (net of capitalized interest of $3 and $2)   $ 35   $ 30  
                        —Income taxes          

See Notes to Condensed Consolidated Financial Statements.

32


SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(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, 2003. 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.    Variable Interest Entity

        The Company adopted Financial Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46), "Consolidation of Variable Interest Entities", effective January 1, 2004, which requires an enterprise's consolidated financial statements to include entities in which the enterprise has a controlling financial interest. The Company has determined that it has a controlling financial interest in South Carolina Generating Company, Inc. (GENCO) under the criteria of FIN 46, and accordingly, the accompanying condensed consolidated financial statements include the accounts of the Company, GENCO and South Carolina Fuel Company, Inc. Prior period amounts have been restated to reflect the adoption of FIN 46. The consolidation resulted in an increase of approximately $336 million in net assets reflected in the condensed consolidated balance sheet for March 31, 2004. The equity interest in GENCO is held solely by SCANA Corporation, the Company's parent. Accordingly, GENCO's equity and results of operations are reflected as a minority interest in the Company's condensed consolidated financial statements, and the adoption of FIN 46 therefore had no impact on the Company's equity, net earnings or cash flows.

        GENCO owns and operates a coal-fired electric generating station with a 615 megawatt net generating capacity (summer rating). GENCO's electricity is sold solely to the Company under the terms of a power purchase and related agreement. Substantially all of GENCO's property (carrying value of approximately $75 million) serves as collateral for its long-term borrowings.

B.    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 certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of March 31, 2004, approximately

33



$320 million and $446 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

Millions of dollars

  March 31,
2004

  December 31,
2003

 
Accumulated deferred income taxes, net   $ 103   $ 104  
Under-(over-)collections—electric fuel and gas cost adjustment clauses, net     7     39  
Deferred environmental remediation costs     10     11  
Asset retirement obligation—nuclear decommissioning     47     48  
Deferred non-conventional fuel tax benefits, net     (74 )   (67 )
Storm damage reserve     (34 )   (37 )
Franchise agreements     60     62  
Non-legal asset retirement obligations     (270 )   (265 )
Other     25     20  
   
 
 
Total   $ (126 ) $ (85 )
   
 
 

        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-(over-)collections—fuel adjustment clauses, net represent amounts under or over-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. Such costs, totaling approximately $9.8 million, are expected to be fully recovered by the end of 2009.

        Asset retirement obligation—nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required by SFAS 143, "Accounting for Asset Retirement Obligations."

        Deferred non-conventional fuel tax benefits, net represent the deferral of partnership losses and other expenses of approximately $44 million, offset by the accumulated deferred income tax credits of approximately $117 million associated with the Company's two partnerships involved in converting coal to synthetic fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced by the partnerships 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 period of approximately ten years. 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 approximately 15 years.

        Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.

34



        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, liquidity or financial position in the period the write-off would be recorded.

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 $26.8 million and $39.5 million payable to SCPC for such gas purchases at March 31, 2004 and December 31, 2003, 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 these affiliated companies for these investments approximately $17.8 million and $13.4 million at March 31, 2004 and December 31, 2003, respectively. The Company had recorded as payables to these affiliated companies approximately $15.6 million and $12.2 million at March 31, 2004 and December 31, 2003, respectively.

D.    Pension and Other Postretirement Benefit Plans

        Components of net periodic benefit income or cost recorded by the Company were as follows:

 
   
   
  Other Postretirement Benefits
 
 
  Pension Benefits
 
Three months ended March 31 (Millions of dollars)

 
  2004
  2003
  2004
  2003
 
Service cost   $ 2.8   $ 2.6   $ 0.8   $ 1.3  
Interest cost     9.1     9.5     2.9     3.8  
Expected return on assets     (17.7 )   (15.0 )        
Prior service cost amortization     1.6     1.6     0.2     0.8  
Transition obligation amortization     0.2     0.2     0.3     0.3  
Actuarial (gain) loss         0.5     0.5     0.2  
Amount attributable to company affiliates     (0.4 )   (0.5 )   (0.9 )   (1.2 )
   
 
 
 
 
Net periodic benefit (income) cost   $ (4.4 ) $ (1.1 ) $ 3.8   $ 5.2  
   
 
 
 
 

E.    Reclassifications

        Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2004.

2.     RATE AND OTHER REGULATORY MATTERS

Electric

        In January 2003, in conjunction with the approval of a retail rate increase, the SCPSC deferred action on the recovery of certain purchased power costs pending the resolution of the appeal of the SCPSC's May 2002 order. In May 2002 the SCPSC approved the Company's request to increase the fuel component of rates charged to electric customers, which reflected higher fuel costs projected for

35



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 Consumer Advocate of South Carolina (Consumer Advocate) 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 Circuit Court ruled that the current fuel clause only provides for the recovery of the fuel costs included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the portion of the purchased power costs not allowed to be recovered through the fuel clause.

        In April 2004 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.678 cents per KWh to 1.821 cents per KWh. The increase reflects higher fuel costs projected for the period May 2004 through April 2005. The increase also provides continued recovery for under-collected actual fuel costs through February 2004. The new rates will be effective as of the first billing cycle in May 2004.

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, 2003 through March 31, 2004 was as follows:

Rate Per Therm

  Effective Date
$ .728   January–February 2003
  .928   March–October 2003
  .877   November 2003–March 2004

        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 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 2003, as a result of the annual review, the SCPSC approved the Company's request to reduce the billing surcharge from 3.0 cents per therm to 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at March 31, 2004 of $9.8 million.

3.     LONG-TERM DEBT

        On February 11, 2004 GENCO issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.

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 March 31, 2004 approximately $45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

36



5.     COMMITMENTS AND CONTINGENCIES

        Reference is made to Note 10 to the consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2003. Commitments and Contingencies at March 31, 2004 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. 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 March 31, 2004 totaled approximately $192 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 $10.8 billion. Each reactor licensee is currently liable for up to $100.6 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 $67.1 million per incident, but not more than $6.7 million per year.

        Congress failed to renew the Price-Anderson Indemnification Act when it expired in 2003. The delayed renewal has no impact on the Company due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.

        The Company currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective 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 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 $9.8 million at March 31, 2004. The deferral includes the estimated costs associated with the following matters.

37



        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 by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of March 31, 2004, the Company has spent approximately $19.8 million to remediate the Calhoun Park site and expects to spend an additional $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 the South Carolina Department of Health and Environmental Control (DHEC). 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. As of March 31, 2004, the Company has spent approximately $3.1 million related to these sites, and expects to spend an additional $4.9 million.

D.    Claims and Litigation

        On August 21, 2003, the Company was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. 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.

        A complaint was filed on October 22, 2003 against the Company by the State of South Carolina alleging that the Company violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint also alleges that the Company failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing in a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. The Company is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are the subject of a similar lawsuit that was filed and served on the Company, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and the Company. The Company further believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, the Company filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to the Company's electric and gas service, to approve the Company's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.

        The Company is 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.

38


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. Intersegment revenues were not significant.

Disclosure of Reportable Segments
(Millions of Dollars)

 
  2004
  2003
Three Months Ended March 31,

  External
Revenue

  Operating
Income

  Segment
Assets

  External
Revenue

  Operating Income
  Segment
Assets

Electric Operations   $ 381   $ 97   $ 5,080   $ 337   $ 84   $ 4,587
Gas Distribution     146     16     325     140     18     315
Adjustments/Eliminations             1,259             1,156
   
 
 
 
 
 
Consolidated Total   $ 527   $ 113   $ 6,664   $ 477   $ 102   $ 6,058
   
 
 
 
 
 

39



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, 2003.

        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, including competition from alternate fuels in industrial interruptible markets, (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 (SCANA) 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. SCE&G disclaims any obligation to update any forward-looking statements.

Electric Operations

        In April 2004 the joint U.S.-Canada Power System Outage Task Force issued its "Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report). The Blackout Report contains 46 recommendations that, if implemented, the Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the Blackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed the House and Senate in 2003 but have stalled in conference committee. Various provisions of the Energy Bill related to electric reliability are being resubmitted as separate legislation (reliability legislation). It is anticipated that any reliability legislation, if passed, would make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the U.S. Federal Energy Regulatory Commission (FERC), enabling it to enact regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could 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 of its service territory.

40



        In addition, the North American Electric Reliability Council (NERC) is expected to proceed with its initiatives to develop, establish and enforce standards for the grid. To that end, NERC is working closely with FERC to implement stronger reliability standards among NERC's voluntary membership. SCE&G, along with other NERC members, is also working closely with NERC in these efforts. Such initiatives would be significantly influenced by any reliability legislation enacted by Congress. If implemented, such initiatives by FERC and NERC could 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.

41


RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2004
AS COMPARED TO THE CORRESPONDING PERIOD IN 2003

Net Income

        Net income for the periods ended March 31, 2004 and 2003 was as follows:

 
  First Quarter
Millions of dollars

  2004
  2003
Net income   $ 53.8   $ 47.0

        Net income increased due to higher electric margins of $16.6 million and a reduction of preferred dividend requirements of $0.9 million, partially offset by lower gas margins of $3.1 million, higher operation and maintenance expense of $3.1 million, higher depreciation expense of $1.6 million, higher property taxes of $2.4 million and higher interest expense of $0.7 million.

Pension Income

        Pension income was recorded on SCE&G's financial statements as follows:

 
  First Quarter
 
Millions of dollars

 
  2004
  2003
 
Income Statement Impact:              
  Reduction in (component of) employee benefit costs   $ 1.4   $ (0.7 )
  Other income     2.5     2.0  
Balance Sheet Impact:              
  Reduction in (component of) capital expenditures     0.4     (0.2 )
  Component of amount due to Summer Station co-owner     0.1      
   
 
 
Total Pension Income   $ 4.4   $ 1.1  
   
 
 

        For the last several years, the market value of SCANA's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. SCE&G's portion of SCANA's pension income in the first quarter of 2004 increased compared to the corresponding period in 2003 primarily as a result of a more favorable investment market.

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 increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project (see discussion at CAPITAL PROJECTS).

42



Dividends Declared

        SCE&G and GENCO's Board of Directors has declared the following dividends on common stock held by SCANA during 2004:

Declaration Date

  Amount
  Quarter Ended
  Payment Date
February 19, 2004   $ 36.0 million   March 31, 2004   April 1, 2004
April 29, 2004   $ 37.0 million   June 30, 2004   July 1, 2004

Electric Operations

        Electric Operations is comprised of the electric operations of SCE&G, GENCO and South Carolina Fuel Company, Inc. Electric operations sales margins were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating Revenues   $ 381.1   13.0%   $ 337.4
Less: Fuel used in generation     95.4   18.1%     80.8
         Purchased power     12.7   21.0%     10.5
   
 
 
Margin   $ 273.0   10.9%   $ 246.1
   
 
 

        Margin increased primarily due to increased retail electric base rates that went into effect in February 2003 for a total impact of $7.1 million, an additional $3.2 million due to favorable weather, $14.6 million from off-system sales and $2.0 million due to customer growth and consumption.

Gas Distribution

        Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins (including transactions with affiliates) were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating Revenues   $ 145.7   4.0%   $ 140.1
Less: Gas purchased for resale     110.8   10.6%     100.2
   
 
 
Margin   $ 34.9   (12.5)%   $ 39.9
   
 
 

        Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and maintenance) and an unfavorable competitive position of natural gas relative to alternate fuels of $1.9 million.

Other Operating Expenses

        Other operating expenses were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Other operation and maintenance   $ 108.7   4.8%   $ 103.7
Depreciation and amortization     51.9   5.3%     49.3
Other taxes     35.0   12.5%     31.1
   
 
 
Total   $ 195.6   6.3%   $ 184.1
   
 
 

43


        Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $2.4 million, 2004 winter storm restoration expenses of $2.5 million and increased expenses at electric generation plants of $3.4 million, partially offset by decreased recovery of environmental remediation expenses of $3.2 million (offset in gas margin) and increased pension income of $2.1 million. Depreciation and amortization expense increased primarily due to normal net property changes. Other taxes increased primarily due to increased property taxes.

Other Income

        Other income, including AFC, decreased primarily due to reduced other non-operating income partially offset by an increase in AFC due to construction expenditures related to the Jasper County Generation Station Project and the Lake Murray Dam Project.

Interest Expense

        Interest expense increased by $3.9 million due to increased long-term debt partially offset by $2.1 million due to lower interest rates and by $1.0 million due to increased AFC.

Income Taxes

        Income taxes increased primarily as a result of changes in operating income.

LIQUIDITY AND CAPITAL RESOURCES

        SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months ended March 31, 2004 was 3.07.

        SCE&G's cash requirements arise primarily from its operational needs, funding its construction programs 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.

        The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the three months ended March 31, 2004 and 2003:

 
  Three Months Ended
March 31,

 
Millions of dollars

 
  2004
  2003
 
Net cash provided from operating activities   $ 53   $ 66  
Net cash provided from financing activities     81     92  
Funds used for investments     (3 )   (4 )
Cash and temporary cash investments available at the beginning of the period     56     23  

Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction

 

$

107

 

$

155

 
Funds used for nonutility property additions     1      

44


        SCE&G intends to file an electric rate case with the SCPSC in the summer of 2004 requesting, among other things, recovery of capital expenditures related to the generating facility in Jasper County, South Carolina. This filing will also include SCE&G's plan to use synthetic fuel tax credits to offset construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the filing within six months of the rate application being filed.

CAPITAL TRANSACTIONS

        On February 11, 2004 GENCO issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.

CAPITAL PROJECTS

        Construction of SCE&G's 875 megawatt generation facility in Jasper County, South Carolina has been completed. The facility includes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility began commercial operation in May 2004.

        In October 1999 FERC mandated that SCE&G reinforce its Lake Murray Dam in order to comply with new federal safety standards. 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 March 31, 2004 totaled approximately $192 million.

ENVIRONMENTAL MATTERS

        For information on environmental matters see Note 5C to condensed consolidated financial statements.

OTHER MATTERS

Nuclear Station

        In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through 2042.

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 March 31, 2004 is approximately $3 million, and through March 31, 2004, they have generated and passed through to SCE&G approximately $107 million in such tax credits. At March 31, 2004 SCE&G has recorded on its balance sheet $74 million net deferred fuel tax benefits, which include partnership losses, net of tax.

        Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced for 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 1B to condensed consolidated financial statements.

        In March 2004 SCANA received a "No Change" letter from the Internal Revenue Service (IRS) related to SCE&G's interest in the synthetic fuel partnership S. C. Coaltech No. l L.P. for the tax year 2000. This letter supports SCANA's position that the synthetic fuel tax credits have been properly claimed.

45




Item 3. Quantitative and Qualitative Disclosures About Market Risk

        All financial instruments held by SCE&G and GENCO 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 and GENCO 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 March 31, 2004
  Expected Maturity Date
Millions of dollars
Liabilities

  2004
  2005
  2006
  2007
  2008
  There-
after

  Total
  Fair
Value

Long-Term Debt:                                
Fixed Rate ($)   139.2   189.2   169.9   39.2   39.2   1,821.9   2,398.6   2,339.8
Average Interest Rate (%)   7.46   7.37   8.51   6.86   6.86   6.03   6.42    

        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 March 31, 2004 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 March 31, 2004 SCE&G's disclosure controls and procedures were effective. There has been no change in SCE&G's internal control over financial reporting during the quarter ended March 31, 2004 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting.

46



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).

47




Item 1. Financial Statements

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

Millions of dollars

  March 31,
2004

  December 31,
2003

 
Assets              
Gas Utility Plant   $ 931   $ 923  
Accumulated depreciation     (261 )   (256 )
Acquisition Adjustment, Net of Accumulated Amortization     210     210  
   
 
 
Gas Utility Plant, Net     880     877  
   
 
 
Nonutility Property and Investments, Net     27     28  
   
 
 
Current Assets:              
  Cash and temporary investments     33     18  
  Restricted cash and temporary investments     8     7  
  Receivables, net of allowance for uncollectible accounts of $3 and $3     96     115  
  Receivables-affiliated companies     6     5  
  Inventories (at average cost):              
    Stored gas     26     56  
    Materials and supplies     5     5  
  Prepayments     1     2  
  Deferred income taxes, net     4     3  
   
 
 
  Total Current Assets     179     211  
   
 
 
Deferred Debits:              
  Due from affiliate-pension asset     13     13  
  Regulatory assets     19     17  
  Other     8     6  
   
 
 
  Total Deferred Debits     40     36  
   
 
 
Total   $ 1,126   $ 1,152  
   
 
 
Capitalization and Liabilities              
Capitalization:              
  Common equity   $ 521   $ 502  
  Long-term debt, net     278     278  
   
 
 
  Total Capitalization     799     780  
   
 
 
Current Liabilities:              
  Short-term borrowings         55  
  Current portion of long-term debt     8     8  
  Accounts payable     35     48  
  Accounts payable-affiliated companies     5     2  
  Customer deposits     7     7  
  Taxes accrued     25     10  
  Interest accrued     4     6  
  Distributions/dividends declared     4     4  
  Other     12     15  
   
 
 
  Total Current Liabilities     100     155  
   
 
 
Deferred Credits:              
  Deferred income taxes, net     96     96  
  Deferred investment tax credits     2     2  
  Due to affiliate-postretirement benefits     17     17  
  Regulatory liabilities     99     86  
  Other     13     16  
   
 
 
  Total Deferred Credits     227     217  
   
 
 
Total   $ 1,126   $ 1,152  
   
 
 

See Notes to Condensed Consolidated Financial Statements.

48


PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

 
  Three Months Ended
March 31,

Millions of dollars

  2004
  2003
Operating Revenues   $ 226   $ 203
Cost of Gas     153     131
   
 
Gross Margin     73     72
   
 
Operating Expenses:            
  Operation and maintenance     20     19
  Depreciation     9     9
  Other taxes     2     2
   
 
  Total Operating Expenses     31     30
   
 
Operating Income     42     42
Other Income, Including Allowance for Equity Funds Used During Construction         2
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction     5     5
   
 
Income Before Income Tax Expense     37     39
Income Tax Expense     14     15
   
 
Net Income   $ 23   $ 24
   
 

See Notes to Condensed Consolidated Financial Statements.

49



PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
  Three Months Ended
March 31,

 
Millions of dollars

 
  2004
  2003
 
Cash Flows From Operating Activities:              
  Net income   $ 23   $ 24  
  Adjustments to reconcile net income to net cash provided from operating activities:              
    Depreciation and amortization     9     9  
    Loss on sale of assets     1      
    Over (under) collection, gas cost adjustment clause     7     (6 )
    Changes in certain assets and liabilities:              
      (Increase) decrease in receivables, net     18     (6 )
      (Increase) decrease in inventories     30     20  
      Increase (decrease) in accounts payable     (10 )   1  
      Increase (decrease) in deferred income taxes, net     (1 )   1  
      Increase (decrease) in regulatory liabilities     1      
      Increase (decrease) in taxes accrued     15     15  
    Changes in other assets         2  
    Changes in other liabilities     (6 )   (8 )
   
 
 
Net Cash Provided From Operating Activities     87     52  
   
 
 
Cash Flows From Investing Activities:              
  Construction expenditures     (13 )   (10 )
  Nonutility and other         (1 )
   
 
 
Net Cash Used For Investing Activities     (13 )   (11 )
   
 
 
Cash Flows From Financing Activities:              
  Repayment of short-term borrowings, net     (55 )   (31 )
  Distributions/dividend payments     (4 )   (5 )
   
 
 
Net Cash Used For Financing Activities     (59 )   (36 )
   
 
 
Net Increase In Cash and Temporary Investments     15     5  
Cash and Temporary Investments, January 1     18     1  
   
 
 
Cash and Temporary Investments, March 31   $ 33   $ 6  
   
 
 
Supplemental Cash Flow Information:              
Cash paid for—Interest (net of capitalized interest of $0.2 and $0.4)   $ 7   $ 6  
                      —Income taxes          

See Notes to Condensed Consolidated Financial Statements.

50



PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(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, 2003. 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 certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded as of March 31, 2004 approximately $19 million and $99 million of regulatory assets and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

Millions of dollars

  March 31,
2004

  December 31,
2003

 
Excess deferred income taxes   $ (2 )    
Over-collections-gas cost adjustment clause, net     (8 ) $ (1 )
Deferred environmental remediation costs     9     9  
Non-legal asset retirement obligations     (79 )   (77 )
   
 
 
Total   $ (80 ) $ (69 )
   
 
 

        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.

        Over-collections-gas cost adjustment clause, net represents amounts over-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 represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. A portion of the costs incurred has been recovered through rates. Approximately $2.4 million in costs have been incurred and deferred for subsequent rate consideration. (See Note 4.) Management believes that all MGP cleanup costs will be recoverable through gas rates.

        Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.

        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.

51



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, liquidity or financial position in the period the write-off would be recorded.

B.    Total Comprehensive Income

        Total comprehensive income was not significantly different from net income for any period reported. Accumulated other comprehensive income (loss) of the Company totaled $(1.1) million and $(1.0) million as of March 31, 2004 and December 31, 2003, respectively.

C.    Reclassifications

        Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2004.

2.     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, 2003 through March 31, 2004 was as follows:

Rate Per Therm

  Effective Date
$ .460   January–February 2003
  .595   March 2003
  .725   April–November 2003
  .600   December 2003–March 2004

        For service rendered on and after March 1, 2004, the NCUC authorized the Company to implement decrements in its sales and transportation rate schedules to reflect a decrease of approximately $5.7 million in the Company's annual fixed gas costs as well as the current over-recovery of approximately $16.5 million.

        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 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion was completed and placed in service in April 2004. Through March 31, 2004 approximately $29 million had been spent on this project.

        In December 1999 the NCUC issued an order approving SCANA Corporation's acquisition of the Company. As specified in the order, the Company agreed to a moratorium on general rate cases until

52



August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events.

3.     FINANCIAL INSTRUMENTS

        The Company follows the guidance required by SFAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas.

        The Company utilizes hedging activities for natural gas purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of March 31, 2004 the Company had deferred net costs of approximately $1.9 million.

        The Company also utilizes swap agreements to manage interest rate risk. At March 31, 2004 the estimated fair value of the Company's swaps totaled $2.7 million related to combined notional amounts of $33.1 million.

4.     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 approximately $6.8 million, which reflects the estimated remaining liability at March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.4 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

5.     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)

 
  2004
  2003
 
Three months Ended March 31,

 
  External
Revenue

  Operating
Income

  Segment
Assets

  External
Revenue

  Operating
Income

  Segment
Assets

 
Gas Distribution   $ 226   $ 42   $ 1,039   $ 203   $ 42   $ 1,023  
All Other         n/a     28         n/a     28  
Adjustments/Eliminations             59             (18 )
   
 
 
 
 
 
 
Consolidated Total   $ 226   $ 42   $ 1,126   $ 203   $ 42   $ 1,033  
   
 
 
 
 
 
 

53



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, 2003.

        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, including competition from alternate fuels in industrial interruptible markets, (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 (SCANA) 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. PSNC Energy disclaims any obligation to update any forward-looking statements.

Net Income and Distributions/Dividends

        Net income decreased for the three months ended March 31, 2004 approximately $1.6 million compared to the same period in 2003 primarily due to higher operating expenses of $1.7 million and lower other income of $1.5 million, partially offset by increased margin of $0.7 million and lower income taxes of $0.9 million.

        The nature of PSNC Energy's business is seasonal. The quarters ending March 31 and December 31 are generally PSNC Energy's most profitable quarters due to increased 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 2004:

Declaration Date

  Amount
  Quarter Ended
  Payment Date

February 19, 2004

 

$4.0 million

 

March 31, 2004

 

April 1, 2004

April 29, 2004

 

$3.5 million

 

June 30, 2004

 

July 1, 2004

54


Gas Distribution

        Gas distribution is comprised of the local distribution operations of PSNC Energy. Changes in the gas distribution sales margins were as follows:

 
  First Quarter
Millions of dollars

  2004
  % Change
  2003
Operating revenues   $ 226.0   11.2 % $ 203.2
Less: Cost of gas     153.4   16.8 %   131.3
   
 
 
Gross margin   $ 72.6   1.0 % $ 71.9
   
 
 

        Gas distribution sales margin for the three months ended March 31, 2004 increased primarily due to customer growth of approximately $1.9 million, higher other operating revenues of $0.3 million and a positive margin impact from changes in the benchmark cost of gas of approximately $0.3 million. This increase was partially offset by a decline in customer usage per degree day of approximately $2.1 million.

Operation and Maintenance Expenses

        Operation and maintenance expenses increased $1.7 million for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to increased labor and benefits costs of $0.9 million and increased administrative and general business expenses of $0.7 million.

Other Income

        Other income decreased $1.5 million compared to the same period in 2003 primarily due to a $1.0 million loss recognized on the sale of PSNC Energy's former corporate headquarters in Gastonia, North Carolina.

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 2004 construction budget is approximately $51 million, compared to actual construction expenditures through March 31, 2004 of $13.4 million. PSNC Energy's ratio of earnings to fixed charges for the 12 months ended March 31, 2004 was 3.27.

        At March 31, 2004 PSNC Energy had no outstanding short-term borrowings and had unused lines of credit of $125 million.


Item 4. Controls and Procedures

        As of March 31, 2004 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 March 31, 2004 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 March 31, 2004 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting.

55




PART II. OTHER INFORMATION

Item 1. Legal Proceedings

        The Company, SCE&G and PSNC Energy are engaged in various claims and litigation incidental to their business operations which management anticipates will be resolved without material loss to the Company. The status of matters previously disclosed in the Company's Annual Report on Form 10-K for 2003 have not changed significantly.


Item 2. Purchases of Equity Securities by the Issuer and Affiliated Purchases

Period
  (a)
Total number of
shares (or units)
purchased

  (b)
Average price paid
per share (or unit)

  (c)
Total number of
shares (or units)
purchased as part of
publicly announced
plans or programs

  (d)
Maximum number
(or approximate
dollar value) of
shares (or units)
that may yet be
purchased under
the plans or
programs

January 1, 2004– January 31, 2004           1,155,670
February 1, 2004– February 29, 2004   55,000   $ 34.54   55,000   1,100,673
March 1, 2004–
March 31, 2004
  60,400   $ 35.86   60,400   1,018,981
   
 
 
 
Total   115,400   $ 35.23   115,400   1,018,981
   
 
 
 

        On October 24, 2003, the Company announced that it would repurchase shares of SCANA stock on the open market. Total shares repurchased could not exceed the aggregate, measured at the time of any such purchase, of the number of shares theretofore issued pursuant to the exercise of options granted under the Long-Term Equity Compensation Plan (the Plan) plus the number of shares issuable upon the exercise of options exercisable under the Plan as of the date of such purchase or to become exercisable within 60 days of such date. No expiration date was stated, and the program under which such repurchases were made did not expire during the period covered by the above table. Effective April 29, 2004, the Company discontinued purchasing outstanding shares of common stock on the open market.


Item 3, 4 and 5 are not applicable.


Item 6. Exhibits and Reports on Form 8-K

        A.    Exhibits

56


        B.    Reports on Form 8-K during the first quarter 2004 were as follows:

 
   
SCANA Corporation:
Date of report:   February 13, 2004
Items reported:   Items 7 & 12

South Carolina Electric & Gas Company:
Date of report:   February 13, 2004
Items reported:   Items 7 & 12

Public Service Company of North Carolina, Incorporated:
Date of report:   February 13, 2004
Items reported:   Items 7 & 12

57



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)

May 5, 2004

 

By:

/s/  
JAMES E. SWAN, IV      
James E. Swan, IV
Controller
(Principal accounting officer)

58



EXHIBIT INDEX

 
  Applicable to Form 10-Q of
   
   
   
Exhibit
No.

  SCANA
  SCE&G
  PSNC
Energy

  Description

3.01   X           Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)

3.02

 

X

 

 

 

 

 

Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)

3.03

 

 

 

X

 

 

 

Restated Articles of Incorporation of South Carolina Electric & Gas Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein)

3.04

 

 

 

X

 

 

 

Articles of Amendment effective as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference herein

 

 

 

 

 

 

 

 

May 22, 2001

 

Exhibit 3.02

 

to Registration No. 333-65460
                June 14, 2001   Exhibit 3.04   to Registration No. 333-65460
                August 30, 2001   Exhibit 3.05   to Registration No. 333-101449
                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
                March 13, 2003   Exhibit 3.05   to Registration No. 333-108760
                May 22, 2003   Exhibit 3.05   to Registration No. 333-108760
                June 18, 2003   Exhibit 3.06   to Registration No. 333-108760
                August 7, 2003   Exhibit 3.06   to Registration No. 333-108760

3.05

 

X

 

 

 

 

 

Articles of Correction filed on June 1, 2001 correcting May 22, 2001 Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein)

3.06

 

 

 

X

 

 

 

Articles of Correction filed on February 17, 2004 correcting the Articles of Amendment dated as indicated below and filed as exhibits to Form 10-K for the year ended December 31, 2003 and are incorporated by reference herein

 

 

 

 

 

 

 

 

May 3, 2001

 

Exhibit 3.06

 

 
                May 22, 2001   Exhibit 3.07    
                June 14, 2001   Exhibit 3.08    
                August 30, 2001   Exhibit 3.09    
                March 13, 2002   Exhibit 3.10    
                May 9, 2002   Exhibit 3.11    
                June 4, 2002   Exhibit 3.12    
                August 12, 2002   Exhibit 3.13    
                March 13, 2003   Exhibit 3.14    
                May 22, 2003   Exhibit 3.15    
                         

59


                June 18, 2003   Exhibit 3.16    
                August 7, 2003   Exhibit 3.17    

3.07

 

X

 

 

 

 

 

By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein)

3.08

 

 

 

X

 

 

 

By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)

3.09

 

 

 

 

 

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 and incorporated by reference herein)

4.01

 

X

 

X

 

 

 

Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)

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 No. 33-32107 and incorporated by reference herein)

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 and incorporated by reference herein)

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 (Exhibit 2-C to Registration Statement No. 2-26459 and incorporated by reference herein)

4.05

 

X

 

X

 

 

 

Fifth through Fifty-third Supplemental Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference herein

 

 

 

 

 

 

 

 

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
                         

60


                September 1, 1968   Exhibit 4-O   to Registration No. 2-31569
                June 1, 1969   Exhibit 4-C   to Registration No. 33-38580
                December 1, 1969   Exhibit 4-O   to Registration No. 2-35388
                June 1, 1970   Exhibit 4-R   to Registration No. 2-37363
                March 1, 1971   Exhibit 2-B-17   to Registration No. 2-40324
                January 1, 1972   Exhibit 2-B   to Registration No. 33-38580
                July 1, 1974   Exhibit 2-A-19   to Registration No. 2-51291
                May 1, 1975   Exhibit 4-C   to Registration No. 33-38580
                July 1, 1975   Exhibit 2-B-21   to Registration No. 2-53908
                February 1, 1976   Exhibit 2-B-22   to Registration No. 2-55304
                December 1, 1976   Exhibit 2-B-23   to Registration No. 2-57936
                March 1, 1977   Exhibit 2-B-24   to Registration No. 2-58662
                May 1, 1977   Exhibit 4-C   to Registration No. 33-38580
                February 1, 1978   Exhibit 4-C   to Registration No. 33-38580
                June 1, 1978   Exhibit 2-A-3   to Registration No. 2-61653
                April 1, 1979   Exhibit 4-C   to Registration No. 33-38580
                June 1, 1979   Exhibit 2-A-3   to Registration No. 33-38580
                April 1, 1980   Exhibit 4-C   to Registration No. 33-38580
                June 1, 1980   Exhibit 4-C   to Registration No. 33-38580
                December 1, 1980   Exhibit 4-C   to Registration No. 33-38580
                April 1, 1981   Exhibit 4-D   to Registration No. 33-38580
                June 1, 1981   Exhibit 4-D   to Registration No. 33-49421
                March 1, 1982   Exhibit 4-D   to Registration No. 2-73321
                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
                February 1, 1987   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. 33-49421
                May 1, 1999   Exhibit 4.04   to Registration No. 333-86387
                         

61



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 and incorporated by reference herein)

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 and incorporated by reference herein)

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 and incorporated by reference herein)

4.09

 

X

 

 

 

X

 

Indenture dated as of January 1, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206 and incorporated by reference herein)

4.10

 

X

 

 

 

X

 

First through Fourth Supplemental 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 and are incorporated by reference herein

 

 

 

 

 

 

 

 

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

4.11

 

X

 

 

 

X

 

PSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516 and incorporated by reference herein)

*10.01

 

X

 

X

 

X

 

SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and incorporated by reference herein)

*10.02

 

X

 

X

 

X

 

SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by reference herein)

*10.03

 

X

 

X

 

X

 

Amendment to SCANA Director Compensation and Deferral Plan adopted April 29, 2004 (Filed herewith)

*10.04

 

X

 

X

 

X

 

SCANA Supplementary Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)

*10.05

 

X

 

X

 

X

 

SCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
                         

62



*10.06

 

X

 

X

 

X

 

SCANA Supplementary Key Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)

*10.07

 

X

 

X

 

X

 

SCANA Long-Term Equity Compensation Plan dated January 2000 (Filed as Exhibit 4.04 to Registration Statement No. 333-37398 and incorporated by reference herein)

*10.08

 

X

 

X

 

X

 

Amendment to SCANA Long-Term Equity Compensation Plan adopted April 29, 2004 (Filed herewith)

*10.09

 

X

 

X

 

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 and incorporated by reference herein)

*10.10

 

X

 

X

 

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 and incorporated by reference herein)

10.11

 

 

 

 

 

X

 

Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206 and incorporated by reference herein)

10.12

 

 

 

 

 

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 and incorporated by reference herein)

10.13

 

 

 

 

 

X

 

Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206 and incorporated by reference herein)

10.14

 

 

 

 

 

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 and incorporated by reference herein)

10.15

 

 

 

 

 

X

 

Service Agreement between PSNC and SCANA Services, Inc., effective January 1, 2004 (Filed herewith)

10.16

 

 

 

X

 

 

 

Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed herewith)

31.01

 

X

 

 

 

 

 

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.02

 

X

 

 

 

 

 

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)

31.03

 

 

 

X

 

 

 

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.04

 

 

 

X

 

 

 

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
                         

63



31.05

 

 

 

 

 

X

 

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.06

 

 

 

 

 

X

 

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)

32.01

 

X

 

 

 

 

 

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.02

 

X

 

 

 

 

 

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.03

 

 

 

X

 

 

 

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.04

 

 

 

X

 

 

 

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.05

 

 

 

 

 

X

 

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.06

 

 

 

 

 

X

 

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

*
Management Contract or Compensatory Plan or Arrangement

64




QuickLinks

INDEX
SCANA CORPORATION FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED FINANCIAL SECTION
PART II. OTHER INFORMATION
SIGNATURES
EXHIBIT INDEX