UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-11429 Public Service Company of North Carolina, Incorporated 56-2128483
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
Indicate by check mark whether the registrants: (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. SCANA Corporation Yes X No South
Carolina Electric & Gas Company Yes X No Public Service Company of North
Carolina, Incorporated Yes X No
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). SCANA Corporation Yes X No South Carolina
Electric & Gas Company Yes No X ----- --------- ---- ------ Public Service
Company of North Carolina, Incorporated Yes No X ---- -------
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Description of Shares Outstanding
Registrant Common Stock at April 30, 2003
SCANA Corporation Without Par Value 110,837,226
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, 2003
and December 31, 2002 ........................................... 4
Condensed Consolidated Statements of Operations for the
Periods Ended March 31, 2003 and 2002........................... 6
Condensed Consolidated Statements of Cash Flows for the
Periods Ended March 31, 2003 and 2002........................... 7
Condensed Consolidated Statements of Comprehensive Income
(Loss) for the Periods Ended March 31, 2003 and 2002............. 8
Notes to Condensed Consolidated Financial Statements.............. 9
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................... 20
Item 3. Quantitative and Qualitative Disclosures About Market Risk....... 27
Item 4. Controls and Procedures.......................................... 28
South Carolina Electric & Gas Company Financial Section.................... 29
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of March 31, 2003
and December 31, 2002 ......................................... 30
Condensed Consolidated Statements of Income for the
Periods Ended March 31, 2003 and 2002.......................... 32
Condensed Consolidated Statements of Cash Flows
for the Periods Ended March 31, 2003 and 2002.................. 33
Notes to Condensed Consolidated Financial Statements............. 34
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 40
Item 3. Quantitative and Qualitative Disclosures About Market Risk........ 45
Item 4. Controls and Procedures........................................... 45
Public Service Company of North Carolina, Incorporated Financial Section... 46
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of March 31,
2003 and December 31, 2002 .................................... 47
Condensed Consolidated Statements of Operations for
the Periods Ended March 31, 2003 and 2002...................... 48
Condensed Consolidated Statements of Cash Flows for the
Periods Ended March 31, 2003 and 2002.......................... 49
Condensed Consolidated Statements of Comprehensive
Income (Loss) for the Periods Ended March 31, 2003 and 2002.... 50
Notes to Condensed Consolidated Financial Statements............. 51
Item 2. Management's Narrative Analysis of Results of Operations......... 55
Item 4. Controls and Procedures.......................................... 56
PART II. OTHER INFORMATION
Item 1. Legal Proceedings................................................ 57
Item 6. Exhibits and Reports on Form 8-K................................. 58
Signatures................................................................ 60
Certifications Required by Rule 13a-14 ................................... 61
Exhibit Index............................................................. 67
Certifications Pursuant to 18 U.S.C. Section 1350......................... 72
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Assets
Utility Plant:
Electric 5,325 $5,228
Gas 1,614 1,593
Other 186 184
- --------------------------------------------------------------------------------
Total 7,125 7,005
Accumulated depreciation and amortization (2,537) (2,476)
- --------------------------------------------------------------------------------
Total 4,588 4,529
Construction work in progress 772 677
Nuclear fuel, net of accumulated amortization 32 38
Acquisition adjustments 230 230
- --------------------------------------------------------------------------------
Utility Plant, Net 5,622 5,474
- --------------------------------------------------------------------------------
Nonutility Property, Net of Accumulated Depreciation 96 95
Investments 232 231
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 328 326
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 367 397
Receivables, net of allowance for
uncollectible accounts of $22 and $17 521 486
Inventories (at average cost):
Fuel 107 166
Materials and supplies 59 61
Emission allowances 9 10
Prepayments 40 40
Deferred income taxes, net 1 -
- ------------------------------------------------------------- ------------------
Total Current Assets 1,104 1,160
- --------------------------------------------------------------------------------
Deferred Debits:
Environmental 22 27
Nuclear plant decommissioning - 87
Assets held in trust, net-nuclear decommissioning 50 -
Pension asset, net 266 265
Other regulatory assets 300 269
Other 151 146
- --------------------------------------------------------------------------------
Total Deferred Debits 789 794
- --------------------------------------------------------------------------------
Total $7,843 $7,754
================================================================================
- -------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2003 2002
- -------------------------------------------------------------------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,220 $2,177
Preferred stock (Not subject to purchase
or sinking funds) 106 106
- -------------------------------------------------------------------------------
Total Stockholders' Investment 2,326 2,283
Preferred Stock, net (Subject to purchase
or sinking funds) 9 9
SCE&G-Obligated Mandatorily Redeemable
Preferred Securities of SCE&G's
Subsidiary Trust, SCE&G Trust I,
holding solely $50 million principal
amount of 7.55% Junior Subordinated
Debentures of SCE&G, due 2027 50 50
Long-Term Debt, net 2,885 2,834
- -------------------------------------------------------------------------------
Total Capitalization 5,270 5,176
- -------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 114 209
Current portion of long-term debt 503 413
Accounts payable 361 362
Customer deposits 38 39
Taxes accrued 54 78
Interest accrued 58 52
Dividends declared 41 39
Deferred income taxes, net - 4
Other 49 77
- -------------------------------------------------------------------------------
Total Current Liabilities 1,218 1,273
- -------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes, net 752 747
Deferred investment tax credits 116 118
Reserve for nuclear plant decommissioning - 87
Asset retirement obligation - nuclear plant 113 -
Postretirement benefits 134 131
Other regulatory liabilities 131 114
Other 109 108
- -------------------------------------------------------------------------------
Total Deferred Credits 1,355 1,305
- -------------------------------------------------------------------------------
Total $7,843 $7,754
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars, except per share amounts 2003 2002
- ------------------------------------------------------------------ -------------
Operating Revenues:
Electric $336 $302
Gas - regulated 427 296
Gas - nonregulated 306 224
- ------------------------------------------------------------------ -------------
Total Operating Revenues 1,069 822
- ------------------------------------------------------------------ -------------
Operating Expenses:
Fuel used in electric generation 81 74
Purchased power 10 5
Gas purchased for resale 571 378
Other operation and maintenance 144 127
Depreciation and amortization 60 54
Other taxes 35 31
- ------------------------------------------------------------------ -------------
Total Operating Expenses 901 669
- ------------------------------------------------------------------ -------------
Operating Income 168 153
- ------------------------------------------------------------------ -------------
Other Income:
Other income, including allowance for
equity funds used during construction
of $5 and $7 16 19
Gain on sale of investments and assets - 15
Impairment of investments - (244)
- ------------------------------------------------------------------ -------------
Total Other Income (Expense) 16 (210)
- ------------------------------------------------------------------ -------------
Income (Loss) Before Interest Charges, Income Taxes,
Preferred Stock Dividends and Cumulative Effect
of Accounting Change 184 (57)
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction of $2 and $3 51 51
Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 1
- ------------------------------------------------------------------ -------------
Income (Loss) Before Income Taxes,
Preferred Stock Dividends and
Cumulative Effect of Accounting Change 132 (109)
Income Tax Expense (Benefit) 46 (39)
- ------------------------------------------------------------------ -------------
Income (Loss) Before Preferred Stock Dividends and
Cumulative Effect of Accounting Change 86 (70)
Cash Dividends on Preferred Stock of Subsidiary
(At stated rates) 2 2
- ------------------------------------------------------------------ -------------
- --------------------------------------------------------------------------- ----
Income (Loss) Before Cumulative Effect of
Accounting Change 84 (72)
Cumulative Effect of Accounting Change, net of taxes - (230)
- --------------------------------------------------------------------- ----------
- --------------------------------------------------------------------- ----------
Net Income (Loss) $84 $(302)
===================================================================== ==========
===================================================================== ==========
Basic and Diluted Earnings (Loss) Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $.75 $(.68)
Cumulative Effect of Accounting Change, net of taxes - (2.20)
- ------------------------------------------------------------------------- ------
- ------------------------------------------------------------------------- ------
Basic and Diluted Earnings (Loss) Per Share $.75 $(2.88)
========================================================================= ======
========================================================================= ======
Weighted Average Shares Outstanding (millions) 110.8 104.7
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income (loss) $84 $(302)
Adjustments to reconcile net income (loss)
to net cash provided from operating
activities:
Cumulative effect of accounting change, net of taxes - 230
Depreciation and amortization 62 55
Amortization of nuclear fuel 6 5
Gain on sale of investments and assets - (15)
Hedging activities (3) 29
Impairment on investments - 244
Allowance for funds used during construction (7) (10)
Over (under) collection, fuel adjustment clauses 16 4
Changes in certain assets and liabilities:
(Increase) decrease in receivables (38) 14
(Increase) decrease in inventories 62 37
(Increase) decrease in pension asset (1) (7)
(Increase) decrease in other regulatory assets (1) 1
Increase (decrease) in deferred income taxes, net 1 (125)
Increase (decrease) in regulatory liabilities 9 10
Increase (decrease) in postretirement benefits 3 2
Increase (decrease) in accounts payable (1) (37)
Increase (decrease) in taxes accrued (24) 8
Increase (decrease) in interest accrued 6 13
Changes in other assets (10) 11
Changes in other liabilities (20) 14
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 144 181
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures,
net of AFC (171) (117)
Proceeds from sale of investments and assets - 313
Increase in nonutility property (3) (2)
Investments in affiliates (4) (16)
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Net Cash Provided From (Used For) Investing Activities (178) 178
- -------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 198 295
Issuance of notes and loans - 397
Repayments:
Mortgage Bonds - (104)
Notes and loans (60) (402)
Dividends and distributions:
Common stock (37) (32)
Preferred stock (2) (2)
Short-term borrowings, net (95) (67)
- -------------------------------------------------------------------------------
Net Cash Provided From Financing Activities 4 85
- -------------------------------------------------------------------------------
Net Increase (Decrease) In Cash and Temporary Investments (30) 444
Cash and Temporary Investments, January 1 397 212
- ------------------------------------------------------------------------------
Cash and Temporary Investments, March 31 367 $656
==============================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $2 and $3) $46 $38
- Income taxes 1 7
Noncash Investing and Financing Activities:
Unrealized gain on securities available for sale,
net of tax - 93
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- ---------------------------------------------------------------- --------------
- ---------------------------------------------------------------- --------------
Net Income (Loss) $84 $(302)
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on securities
available for sale - 93
Unrealized gains (losses) on hedging activities (2) 24
- ---------------------------------------------------------------- --------------
- ---------------------------------------------------------------- --------------
Total Comprehensive Income (Loss) (1) $82 $(185)
================================================================ ==============
(1) Accumulated other comprehensive income (loss) of the Company totaled $(1.0)
million and $1.0 million as of March 31, 2003 and December 31, 2002,
respectively.
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2003
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in SCANA Corporation's (the Company)
Annual Report on Form 10-K for the year ended December 31, 2002. These are
interim financial statements, and due to the seasonality of the Company's
business, the amounts reported in the Condensed Consolidated Statements of
Operations are not necessarily indicative of amounts expected for the year. In
the opinion of management, the information furnished herein reflects all
adjustments, all of a normal recurring nature, which are necessary for a fair
statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result the Company has
recorded, as of March 31, 2003, approximately $322 million and $131 million of
regulatory assets and liabilities, respectively, as shown below.
March 31, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Accumulated deferred income taxes, net $95 $95
Under- (over-) collections - electric
fuel and gas cost adjustment clauses 45 61
Deferred environmental remediation costs 22 27
Asset retirement obligation - nuclear decommissioning 36 -
Deferred non-conventional fuel tax benefits, net (45) (40)
Storm damage reserve (33) (32)
Franchise agreements 65 65
Other 6 6
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total $191 $182
================================================================================
Accumulated deferred income taxes represent deferred income tax
liabilities applicable to utility operations that have not been reflected in
customer rates for which future recovery is probable, offset by deferred income
tax assets, which will be reflected in customer rates as a result of reduced
revenue requirements due to the amortization of deferred investment tax credits.
Under- (over-) collections - fuel adjustment clauses represent amounts
over- or under-collected from customers pursuant to the fuel adjustment clause
(electric customers) or gas cost adjustment clause (gas customers) as approved
by the Public Service Commission of South Carolina (SCPSC) or North Carolina
Utilities Commission (NCUC) during annual hearings.
Deferred environmental remediation costs represent costs associated
with the assessment and clean up of manufactured gas plant (MGP) sites currently
or formerly owned by the Company. Costs incurred at sites owned by South
Carolina Electric &Gas Company (SCE&G) are being recovered through rates, and
such costs, totaling approximately $14 million, are expected to be fully
recovered by the end of 2005. A portion of the costs incurred at sites owned by
Public Service Company of North Carolina, Incorporated (PSNC Energy) is also
being recovered through rates, and management believes the remaining costs of
approximately $7.8 million will be recoverable in the future. Amounts incurred
to date that have not been recovered through gas rates are approximately $1.2
million.
Asset retirement obligation - nuclear decommissioning represents the
regulatory asset associated with the legal obligation of decommissioning and
dismantling V. C. Summer Nuclear Station (Summer Station) as required in SFAS
143, "Accounting for Asset Retirement Obligations." (See Note 1B).
Deferred non-conventional fuel tax benefits represent the deferral of
partnership losses and other expenses, offset by the accumulated deferred income
tax credits associated with two SCE&G partnerships involved in converting coal
to alternate fuel. Under a plan approved by the SCPSC, any net tax credits
generated from non-conventional fuel produced and consumed by SCE&G and
ultimately passed through to SCE&G have been and will be deferred and will be
applied to offset the capital costs of projects required to comply with
legislative or regulatory actions.
The storm damage reserve represents an SCPSC approved reserve account
capped at $50 million to be collected through rates over a ten-year period. The
accumulated storm damage reserve can be applied to offset actual storm damage
costs in excess of $2.5 million in a calendar year.
Franchise agreements represent costs associated with the 30-year
electric and gas franchise agreements with the cities of Charleston and
Columbia, South Carolina. These amounts are not earning a return, but are being
amortized through cost of service over the next 15 years.
The SCPSC and the NCUC have reviewed and approved through specific
orders most of the items shown as regulatory assets. Other items represent costs
which are not yet approved for recovery by the SCPSC or the NCUC. In recording
these costs as regulatory assets, management believes the costs will be
allowable under existing rate-making concepts that are embodied in rate orders
received by the Company. However, ultimate recovery is subject to SCPSC or NCUC
approval. In the future, as a result of deregulation or other changes in the
regulatory environment, the Company may no longer meet the criteria for
continued application of SFAS 71 and could be required to write off its
regulatory assets and liabilities. Such an event could have a material adverse
effect on the Company's results of operations in the period the write-off would
be recorded, but it is not expected that cash flows or financial position would
be materially affected.
B. New Accounting Standards
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets,"
effective January 1, 2002. In connection with this implementation, the Company
performed a valuation analysis of its investment in South Carolina Pipeline
Corporation (SCPC) using a discounted cash flow analysis and of PSNC Energy
using an independent appraisal. The analysis of the investment in PSNC Energy
indicated that the carrying amount of PSNC Energy's acquisition adjustment
exceeded its fair value by approximately $230 million, or $2.20 loss per share,
effective January 1, 2002. The resulting impairment charge is reflected on the
Condensed Consolidated Statement of Operations as the cumulative effect of an
accounting change. SFAS 142 requires that an impairment test be performed
annually and at the same time each year. The Company performed its test
effective January 1, 2003 and no further impairment resulted.
The Company adopted SFAS 143 effective January 1, 2003. SFAS 143
applies to legal obligations associated with the retirement of tangible
long-lived assets (ARO) and requires the Company to recognize, as a liability,
the fair value of an ARO in the period in which it is incurred and to accrete
the liability to its present value in future periods. As of December 31, 2002,
prior to the adoption of SFAS 143, the Company carried deferred debits and
deferred credits each totaling approximately $87 million related to the
decommissioning and dismantling of Summer Station and the funding thereof.
Effective January 1, 2003, in connection with the measurement of the ARO upon
the adoption of SFAS 143, the amounts reflected within these regulatory assets
and liabilities were recharacterized.
The following table presents such recharacterized amounts related to the
decommissioning obligation and the funding thereof as recorded in the
consolidated balance sheet as of March 31, 2003 and the pro forma amounts that
would have been recorded as of December 31, 2002 had SFAS 143 been adopted at
the beginning of 2002.
As of
March 31, December 31,
2003 2002
Actual Proforma
Assets:
Within electric plant $40 $40
Within accumulated depreciation (13) (13)
Assets held in trust (net) - nuclear decommissioning 50 50
Within other regulatory assets 36 34
----------- -------------
----------- -------------
Total $113 $111
=========== =============
=========== =============
Liabilities:
Asset retirement obligation - nuclear
plant decommissioning $113 $111
=========== =============
Proforma net income (loss) and earnings (loss) per share for periods
prior to the adoption of SFAS 143 would not differ from amounts actually
recorded during these periods.
In addition to the ARO for Summer Station, the Company believes that
there is legal uncertainty as to the existence of environmental obligations
associated with certain transmission and distribution properties. The Company
believes that any ARO related to this type of property would be insignificant
and, due to the indeterminate life of the related assets, an ARO could not be
reasonably estimated.
The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. The provisions of SFAS 145, among other things,
discontinue treatment of gains or losses from the early extinguishment of debt
as extraordinary items unless such early extinguishment meets the criteria of
Accounting Principles Board Opinion (APB) 30. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. This statement requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.
C. Equity Compensation Plan
Under the SCANA Corporation Long-Term Equity Compensation Plan, certain
employees and non-employee directors may receive incentive and nonqualified
stock options and other forms of equity compensation. The Company accounts for
this equity-based compensation using the intrinsic value method under APB 25,
"Accounting for Stock Issued to Employees" and related interpretations. In
addition, the Company has adopted the disclosure provisions of SFAS 123,
"Accounting for Stock-Based Compensation and, effective January 1, 2003, the
disclosure provisions of SFAS 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure." At March 31, 2003, options issued and
outstanding under the Plan totaled approximately 1.7 million.
All options were granted with exercise prices equal to the fair market
value of the Company's stock on the respective grant dates; therefore, no
compensation expense has been recognized in connection with such grants. If the
Company had determined compensation expense for the issuance of options based on
the fair value method described in SFAS 123, pro forma net income and earnings
(loss) per share would have been as presented below:
Three Months Ended
March 31,
2003 2002
---- ----
Net income (loss) - as reported (millions) $83.6 $(301.9)
Net income (loss) - pro forma (millions) 83.2 (302.3)
Basic and diluted earnings (loss) per share - as reported .75 (2.88)
Basic and diluted earnings (loss) per share - pro forma .75 (2.88)
D. Earnings (Loss) Per Share
Earnings (loss) per share amounts have been computed in accordance with
SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are
computed by dividing net income by the weighted average number of common shares
outstanding for the period. Diluted earnings per share are computed as net
income divided by the weighted average number of shares of common stock
outstanding during the period after giving effect to securities considered to be
dilutive potential common stock. The Company uses the treasury stock method in
determining total dilutive potential common stock.
E. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2003.
2. ACCOUNTING CHANGE
As a result of the January 1, 2002 adoption of SFAS 142, the Company
recorded a $230 million impairment charge related to the acquisition adjustment
recorded in connection with its investment in PSNC Energy. This charge is
reflected on the Condensed Consolidated Statements of Operations as the
cumulative effect of an accounting change. See additional information at Note
1B.
3. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company (SCE&G)
Electric
In January 2003 the SCPSC issued an order granting SCE&G an
increase in retail electric rates of 5.8% which is designed to produce
additional annual revenues of approximately $70.7 million based on a test year
calculation. The SCPSC authorized a return on common equity of 12.45%. The new
rates were effective for service rendered on and after February 1, 2003. As a
part of the order, the SCPSC extended through 2005 its approval of the
accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the
plan, based on the level of revenues and operating expenses, SCE&G may increase
depreciation of its Cope Generating Station in excess of amounts that would be
recorded based upon currently approved depreciation rates, not to exceed $36
million annually, without the approval of the SCPSC. Any unused portion of the
$36 million in any given year may be carried forward for possible use in the
following year.
In May 2002 the SCPSC issued an order approving SCE&G's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for under-collected actual fuel costs through April 2001,
including short-term purchased power costs necessitated by outages at two of
SCE&G's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002. The Consumer Advocate of
South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the
portion of the SCPSC's order related to the recovery of certain purchased power
costs. The appeal is still pending.
In January 2003, in conjunction with the approval of the above retail
rate increase, the SCPSC approved SCE&G's request to reduce the fuel component
to 1.678 cents per KWh. This reduction was effective for service rendered on and
after February 1, 2003. In April 2003 the SCPSC issued an order approving
SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per
KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's
purchasing practices and recognized the efficiency of SCE&G's electric
generating plants; however, it deferred action on the recovery of certain
purchased power costs pending the appeal to the Circuit Court of the SCPSC's May
2002 order.
Gas
SCE&G's rates are established using a cost of gas component approved by
the SCPSC which may be modified periodically to reflect changes in the price of
natural gas purchased by SCE&G.
SCE&G's cost of gas component in effect during the period January 1,
2002 through March 31, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002
$.928 March 2003 $.728 November-December 2002
The SCPSC allows SCE&G to recover through a billing surcharge to its
gas customers the costs of environmental cleanup at the sites of former MGPs.
The billing surcharge is subject to annual review and provides for the recovery
of substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for SCE&G's gas operations that had previously
been recorded in deferred debits. In October 2002, as a result of the annual
review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm,
which is intended to provide for the recovery, prior to the end of the year
2005, of the balance remaining at March 31, 2003 of $13.6 million.
Public Service Company of North Carolina, Incorporated (PSNC Energy)
PSNC Energy's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. PSNC Energy revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the delivered cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing
practices annually.
PSNC Energy's benchmark cost of gas in effect during the period January
1, 2002 through March 31, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002
$.595 March 2003 $.215 February-June 2002
$.350 July-October 2002
$.410 November-December 2002
On March 31, 2003 the NCUC approved PSNC Energy's request to increase
the benchmark cost of gas from $.595 per therm to $.725 per therm effective for
service rendered on and after April 1, 2003.
A state expansion fund, established by the North Carolina General
Assembly and funded by refunds from PSNC Energy's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC
Energy's requests for disbursement of up to $28.4 million from PSNC Energy's
expansion fund to extend natural gas service to Madison, Jackson and Swain
Counties in western North Carolina. PSNC Energy estimates that the cost of this
project will be approximately $31.4 million. The Madison County and Jackson
County portions of the project were completed in 2002. Through March 31, 2003
approximately $17.0 million had been spent on this project.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC Energy. As specified in the order, PSNC Energy agreed to a moratorium on
general rate cases until August 2005. General rate relief can be obtained during
this period to recover costs associated with material adverse governmental
actions and force majeure events.
South Carolina Pipeline Corporation (SCPC)
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. A hearing is scheduled for May 15,
2003 to review the period April 2002 through December 2002 to determine if
SCPC's gas purchasing policies and practices were prudent and if SCPC properly
adhered to the gas cost recovery provisions of its gas tariff for that period.
4. LONG-TERM DEBT
On January 13, 2003 SCANA retired at maturity $60 million of 6.05%
medium-term notes.
On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds
having an annual interest rate of 5.80% and maturing on January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt and
for general corporate purposes.
5. RETAINED EARNINGS
The Company's Restated Articles of Incorporation do not limit the
dividends that may be paid on its common stock. However, the Restated Articles
of Incorporation of SCE&G contain provisions that, under certain circumstances,
could limit the payment of cash dividends on its common stock. In addition, with
respect to hydroelectric projects, the Federal Power Act requires the
appropriation of a portion of certain earnings therefrom. At March 31, 2003
approximately $41.5 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.
6. FINANCIAL INSTRUMENTS
Investments
Certain of SCANA's subsidiaries hold investments in marketable
securities, some of which are subject to SFAS 115 "Accounting for Certain
Investments in Debt and Equity Securities," mark-to-market accounting and some
of which are considered cost basis investments for which determination of fair
value historically has been considered impracticable. Equity holdings subject to
SFAS 115 are categorized as "available for sale" and are carried at quoted
market prices, with any unrealized gains and losses credited or charged to other
comprehensive income (loss) within common equity on the Company's balance sheet.
Debt securities and preferred stock with significant debt characteristics are
categorized as "held to maturity" and are carried at amortized cost. When
indicated, and in accordance with its stated accounting policy, SCANA performs
periodic assessments of whether any decline in the value of these securities to
amounts below SCANA's cost basis is other than temporary. When other than
temporary declines occur, write-downs are recorded through operations, and new
(lower) cost bases are established.
Telecommunications Investments
At March 31, 2003 SCANA Communications Holdings, Inc. (SCH), a wholly
owned, indirect subsidiary of SCANA, held investments in the equity and debt
securities of the following companies in the amounts noted in the table below.
Investee Securities Basis
- ------------- ------------------------------------------------ -----------------
(Millions of dollars)
ITC Holding 3.1 million shares common stock $5.8
645,153 shares series A preferred stock, convertible
into 2.6 million shares of common stock 7.2
133,664 shares series B preferred stock, convertible
into 534,656 shares of common stock 4.0
ITC^DeltaCom 566,010 shares of common stock 1.1
151,168 shares series A 8% preferred stock,
convertible in 2005 into 2.6 million shares of
common stock 12.8
Warrants to purchase 506,861.8 shares of common stock 1.1
Knology 7.2 million shares series A preferred stock,
convertible into 7.5 million shares of common stock 14.0
14.8 million shares series C preferred stock,
convertible into 14.8 million shares of common stock 35.1
21.7 million shares series E preferred stock,
convertible into 21.7 million shares of common stock 40.6
$42.8 million face amount, 12% senior unsecured
notes due 2009, including accrued interest 45.0
ITC Holding Company (ITC Holding) holds ownership interests in several
Southeastern communications companies. As these securities are not actively
traded, determination of their fair value is not practicable. ITC^DeltaCom, Inc.
(ITC^DeltaCom) is a regional provider of telecommunications services. Knology,
Inc. (Knology) is a broadband service provider of cable television, telephone
and internet services. The market value of Knology securities is not readily
determinable.
The common shares of ITC^DeltaCom owned by SCH have a market value of
$0.9 million. The preferred shares owned by SCH are classified as held to
maturity due to their debt features, and the market value is not readily
determinable.
Derivatives
SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended, requires the Company to recognize all derivative
instruments as either assets or liabilities in the statement of financial
position and to measure those instruments at fair value. SFAS 133 further
provides that changes in the fair value of derivative instruments are either
recognized in earnings or reported as a component of other comprehensive income
(loss), depending upon the intended use of the derivative and the resulting
designation. The fair value of the derivative instruments is determined by
reference to quoted market prices of listed contracts, published quotations or
quotations from independent parties.
Policies and procedures and risk limits are established to control the
level of market, credit, liquidity and operational and administrative risks
assumed by the Company. The Company's Board of Directors has delegated to a Risk
Management Committee the authority to set risk limits, establish policies and
procedures for risk management and measurement, and oversee and review the risk
management process and infrastructure. The Risk Management Committee, which is
comprised of certain officers, including the Company's Risk Management Officer,
and senior officers of the Company, apprises the Board of Directors with regard
to the management of risk and brings to the Board's attention any areas of
concern. Written policies define the physical and financial transactions that
are approved, as well as the authorization requirements and limits for
transactions that are allowed.
Commodities
The Company uses derivative instruments to hedge anticipated future
purchases of natural gas, which create market risks of different types.
Instruments designated as cash flow hedges are used to hedge risks associated
with fixed price obligations in a volatile price market and risks associated
with price differentials at different delivery locations. Instruments designated
as fair value hedges are used to hedge operational storage assets. The basic
types of financial instruments utilized are exchange-traded instruments, such as
New York Mercantile Exchange futures contracts or options, and over-the-counter
instruments such as swaps, which are typically offered by energy and financial
institutions.
The Company recognized gains (losses) of approximately $5.6 million and
$(19.0) million, net of tax, as a result of qualifying cash flow hedges related
to nonregulated operations during the three months ended March 31, 2003 and
2002, respectively. These gains and losses were recorded in cost of gas. The
Company estimates that most of the March 31, 2003 unrealized gain balance of
$0.1 million, net of tax, will be reclassified from accumulated other
comprehensive income (loss) to earnings in 2003 as a decrease to realized gas
cost if market prices remain stable. As of March 31, 2003, all of the Company's
cash flow hedges settle by their terms before the end of 2006.
The Company recorded option premiums of $0.5 million and gains of $0.4
million, net of tax, as a result of qualifying fair value hedges during the
three months ended March 31, 2003. The premiums and gains were recorded in cost
of gas. As of March 31, 2003 all of the Company's fair value hedges settle by
their terms before the end of 2003.
On January 2, 2003 PSNC Energy filed a summary of its hedging program for
natural gas purchases with the NCUC for informational purposes. The primary goal
of the program is to reduce price volatility to firm customers. The program and
any related transactions will be addressed in the 2003 annual prudence review
with the NCUC. Transaction fees and any gains or losses are recorded in deferred
accounts for subsequent rate consideration.
SCPC's tariffs include a purchased gas adjustment (PGA) clause that
provides for the recovery of actual gas costs incurred. The SCPSC has ruled that
the results of SCPC's hedging activities are to be included in the PGA. As such,
costs of related derivatives that SCPC utilizes to hedge its gas purchasing
activities are recoverable through its weighted average cost of gas calculation.
The offset to the change in fair value of these derivatives is recorded as a
current asset or liability.
The Company also utilizes certain derivative instruments that do not
qualify as hedges. The change in fair value of these derivatives is recorded in
net income (loss), and was insignificant in the periods presented.
Interest Rates
The Company uses interest rate swap agreements to manage interest rate
risk. These swap agreements provide for the Company to pay variable and receive
fixed interest payments and are designated as fair value hedges of certain debt
instruments. The Company may terminate a swap agreement and may replace it with
a new swap also designated as a fair value hedge.
Payments received upon termination of a swap are recorded as basis
adjustments to long term debt and are amortized as reductions to interest
expense over the term of the underlying debt. The fair value of interest rate
swaps is recorded within other deferred debits on the balance sheet. The fair
value of the debt that is hedged is recorded in long-term debt. Periodic
receipts or payments related to the interest rate swaps are credited or charged
to interest expense as incurred.
At March 31, 2003 the estimated fair value of the Company's swaps totaled
$11.7 million related to combined notional amounts of $340.6 million.
7. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 12 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002. Commitments and contingencies at March 31, 2003 include
the following:
A. Lake Murray Dam Reinforcement
In October 1999 the United States Federal Energy Regulatory Commission
(FERC) mandated that SCE&G reinforce its Lake Murray dam in order to comply with
new federal safety standards and maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001 is expected to cost approximately $275 million and be
completed in 2005. Costs incurred through March 31, 2003 totaled approximately
$83 million.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public liability
for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 million of the liability per reactor would be
assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership
of Summer Station, would be approximately $58.7 million per incident, but not
more than $6.7 million per year.
The Price-Anderson Indemnification Act expired in August 2002, but is
expected to renew with only modest changes in 2003. This has no impact on SCE&G
at present due to the "grandfathered" status of existing licensees that are
covered under the past act until such time as it is renewed.
SCE&G currently maintains policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric Insurance Limited. The policies, covering the
nuclear facility for property damage, excess property damage and outage costs,
permit assessments under certain conditions to cover insurer's losses. Based on
the current annual premium, SCE&G's portion of the retrospective premium
assessment would not exceed $15.5 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and expenses arising
from a nuclear incident at Summer Station exceed the policy limits of insurance,
or to the extent such insurance becomes unavailable in the future, and to the
extent that SCE&G's rates would not recover the cost of any purchased
replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G
has no reason to anticipate a serious nuclear incident at Summer Station. If
such an incident were to occur, it would have a material adverse impact on the
Company's results of operations, cash flows and financial position.
C. Environmental
The Company maintains an environmental assessment program to identify
and evaluate current and former operations sites that could require
environmental cleanup. As site assessments are initiated, estimates are made of
the amount of expenditures, if any, deemed necessary to investigate and clean up
each site. These estimates are refined as additional information becomes
available; therefore, actual expenditures could differ significantly from the
original estimates. Amounts estimated and accrued to date for site assessments
and cleanup relate solely to regulated operations.
South Carolina Electric & Gas Company
At SCE&G, site assessment and cleanup costs are deferred and amortized
with recovery provided through rates. Deferred amounts, net of amounts
previously recovered through rates and insurance settlements, totaled $13.6
million at March 31, 2003. The deferral includes the estimated costs associated
with the following matters.
SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. SCE&G
anticipates that the remaining remediation activities will be completed in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
March 31, 2003, SCE&G has spent approximately $18.6 million to remediate the
Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. Two of these sites are currently being
remediated under work plans approved by DHEC. SCE&G is continuing to investigate
the remaining site and is monitoring the nature and extent of residual
contamination. SCE&G anticipates that major remediation activities for these
three sites will be completed before 2006. SCE&G has spent approximately $2.3
million related to these sites, and expects to spend an additional $5.8 million.
In addition, in March 2003 SCE&G signed a consent agreement with DHEC
related to a site formerly owned by SCE&G. The estimated cost for remediation of
this site has not been finalized but is not expected to be material.
Public Service Company of North Carolina, Incorporated
PSNC Energy is responsible for environmental cleanup at five sites in
North Carolina on which MGP residuals are present or suspected. PSNC Energy's
actual remediation costs for these sites will depend on a number of factors,
such as actual site conditions, third-party claims and recoveries from other
potentially responsible parties. PSNC Energy has recorded a liability and
associated regulatory asset of $7.8 million, which reflects the estimated
remaining liability at March 31, 2003. Amounts incurred to date that have not
been recovered through gas rates are approximately $1.2 million. Management
believes that all MGP cleanup costs incurred will be recoverable through gas
rates.
D. Long-Term Natural Gas Contract
In 2001 a subsidiary of the Company entered into, in the ordinary course
of business, a 15 year take-and-pay contract with an unaffiliated natural gas
supplier (Supplier) to purchase 190,000 DT of natural gas per day beginning in
the spring of 2004. In December 2002, as a result of the failure of Supplier and
its guarantor to meet contractual obligations related to credit support
provisions, the subsidiary terminated the contract. Attempts to negotiate a new
contract between the parties were not successful, and a hearing under the
binding arbitration provisions of the original contract is scheduled for June
2003. In initial pleadings for the hearing, the Supplier has demanded payment of
at least $134 million in damages from the subsidiary; conversely, the subsidiary
has demanded payment of no less than $154 million in damages from the Supplier.
The Company is confident of the propriety of its actions and will vigorously
pursue its position in such arbitration proceedings. The Company further
believes that the resolution of these claims will not have a material adverse
impact on its results of operations, cash flows or financial condition.
8. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The
Company uses operating income to measure profitability for its regulated
operations. Therefore, net income is not allocated to the Electric Operations,
Gas Distribution and Gas Transmission segments. The Company uses net income to
measure profitability for its Retail Gas Marketing and Energy Marketing
segments. Accumulated depreciation is not assignable to Electric Operations and
Gas Distribution segments. Gas Distribution is comprised of the local
distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria
for aggregation.
Disclosure of Reportable Segments
(Millions of dollars)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Three Months Ended External Intersegment Operating Net Segment
March 31, 2003 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $336 $2 $84 n/a $6,010
Gas Distribution 343 - 61 n/a 1,478
Gas Transmission 84 108 5 n/a 326
Retail Gas Marketing 183 - n/a $13 124
Energy Marketing 123 - n/a (2) 66
Telecommunications Investments - - - 1 193
All Other - 67 - (2) 397
Adjustments/Eliminations - (177) 18 74 (751)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $1,069 $- $168 $84 $7,843
================================== ============= ============== =============== ================= ===============
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Three Months Ended External Intersegment Operating Net Segment
March 31, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $302 $1 $87 n/a $5,423
Gas Distribution 241 1 54 n/a 1,639
Gas Transmission 55 73 (8) n/a 293
Retail Gas Marketing 156 - n/a $14 100
Energy Marketing 68 - n/a (1) 73
Telecommunications Investments - - - (150) 470
All Other - 69 21 15 606
Adjustments/Eliminations - (144) (1) (180) (715)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $822 $- $153 $(302) $7,889
================================== ============= ============== =============== ================= ===============
9. SUBSEQUENT EVENTS
On April 4, 2003 SCANA redeemed $100 million of floating rate medium-term
notes that were set to mature August 8, 2003. The notes were bearing
interest at a rate of 2.215% when redeemed.
On May 9, 2003, the Company's investment in ITC Holding Company. Inc. was
sold. The sale resulted in the receipt of net after-tax cash proceeds of
approximately $40 million and the receipt of an investment interest in a newly
formed entity valued at approximately $15 million. A book gain, net of tax, of
approximately $40 million was realized upon this sale.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- --------------------------------------------------------------------------------
SCANA CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations
appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for
the year ended December 31, 2002.
Statements included in this discussion and analysis (or elsewhere in
this quarterly report) which are not statements of historical fact are intended
to be, and are hereby identified as, "forward-looking statements" for purposes
of the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility and nonutility
regulatory environment, (3) changes in the economy, especially in areas served
by the Company's subsidiaries, (4) the impact of competition from other energy
suppliers, (5) growth opportunities for the Company's regulated and diversified
subsidiaries, (6) the results of financing efforts, (7) changes in the Company's
accounting policies, (8) weather conditions, especially in areas served by the
Company's subsidiaries, (9) performance of and marketability of the Company's
investments in telecommunications companies, (10) performance of the Company's
pension plan assets, (11) inflation, (12) changes in environmental regulations,
(13) volatility in commodity natural gas markets and (14) the other risks and
uncertainties described from time to time in the Company's periodic reports
filed with the United States Securities and Exchange Commission (SEC). The
Company disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina, electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2003. At the
federal level, the House of Representatives has passed the Energy Policy Act of
2003, and the Senate is expected to approve similar legislation. Some of the
more stringent provisions of this legislation, either currently included or
expected to be debated in conference committee, would require that one percent
of the electric energy sold by retail electric suppliers, beginning in 2005,
escalating to ten percent by 2020, be generated from renewable energy resources.
Renewable energy resources, as defined in the legislation, may exclude
hydroelectric generation. Substantial penalties would be levied for failure to
comply. Electric cooperatives and municipal utilities would be exempt from these
requirements. The Company cannot predict whether such legislation will be
enacted, and if it is, the conditions it would impose on utilities.
In July 2002 the United States Federal Energy Regulatory Commission
(FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design
(SMD) which proposes sweeping changes to the country's existing regulatory
framework governing transmission, open access and energy markets and will
attempt, in large measure, to standardize the national energy market. If
implemented, the proposed rule may have a significant impact on South Carolina
Electric and Gas Company's (SCE&G) access to or cost of power for its native
load customers and on SCE&G's marketing of power outside its service territory.
On April 28, 2003, FERC issued a "white paper" regarding SMD which describes how
the final SMD rule will differ from the NOPR. The Company is currently
evaluating FERC's action to determine potential effects on SCE&G's operations.
Additional directives from FERC are expected.
Gas Distribution
Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, the other household energy needs of
residential and small commercial customers. This competition is generally based
on price and convenience. Large commercial and industrial customers often have
the ability to switch from natural gas to an alternate fuel, such as propane or
fuel oil. Natural gas competes with these alternate fuels based on price. As a
result, any significant disparity between supply and demand, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect the price and impact the Company's ability to
retain large commercial and industrial customers on a monthly basis.
Gas Transmission
In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC
to acquire an interest in an existing pipeline and to build a pipeline from Elba
Island, Georgia to Jasper County, South Carolina. When operational, SCG will
provide interstate transportation services for natural gas to markets in
southeastern Georgia and South Carolina. SCG will transport natural gas from
interconnections with Southern Natural at Port Wentworth, Georgia, and from an
import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia.
The endpoint of SCG's pipeline will be at the site of the natural gas-fired
generating station that SCE&G is building in Jasper County, South Carolina.
Construction of the pipeline began in March 2003, with completion expected in
the fall of 2003, at a cost of approximately $32 million.
South Carolina Pipeline Corporation (SCPC) supplies natural gas to SCE&G,
for its resale to gas distribution customers and for certain electric generation
needs. Gas transmission also sells natural gas to large commercial and
industrial customers in South Carolina, and it faces the same competitive
pressures as gas distribution for these classes of customers.
Retail Gas Marketing
The Georgia Public Service Commission (GPSC) continues to implement
provisions of the Natural Gas Consumer's Relief Act of 2002 (the Act). Among
other things, the Act created a regulated provider selected through a bidding
process to serve low-income and high credit risk customers. The Act also
established new service quality standards and addressed assignment of interstate
assets. The GPSC is expected to finalize the new service quality standards and
implement assignment of interstate assets in the summer of 2003.
SCANA Energy, a division of SCANA Energy Marketing, Inc. which markets
natural gas in Georgia's retail natural gas market, continues to serve as
Georgia's regulated provider. In this capacity, SCANA Energy serves low-income
customers generally at below-market rates, subsidized by Georgia's Universal
Service Fund, and extends service generally at above-market rates to high credit
risk customers who have been denied service by other marketers. At March 31,
2003 approximately 20,000 customers were being served by SCANA Energy under this
program.
SCANA Energy and SCANA's other natural gas distribution, transmission
and marketing segments maintain gas inventory and also utilize forward contracts
and financial instruments, including futures contracts and options, to manage
their exposure to fluctuating commodity natural gas prices. As a part of this
risk management process, at any given time, a portion of SCANA's projected
natural gas needs has been purchased or otherwise placed under contract. This
factor and others (e.g., the level of bad debts experienced) are, in the
aggregate, used to establish retail pricing levels at SCANA Energy. As a result
of the regulatory actions discussed above and other downward pricing pressures
inherent in a competitive market, SCANA Energy may be unable to sustain its
current levels of customers and/or pricing, thereby reducing expected margins
and profitability.
LIQUIDITY AND CAPITAL RESOURCES
The Company anticipates that its contractual cash obligations will be
met through internally generated funds and the incurrence of additional
short-term and long-term indebtedness. Sales of additional equity securities may
also occur. The Company expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the foreseeable future.
The Company's ratio of earnings to fixed charges for the 12 months ended March
31, 2003 (including the effects of nonrecurring impairment charges) was 1.58.
In January 2003 the Public Service Commission of South Carolina (SCPSC)
issued an order granting SCE&G an increase in retail electric rates of 5.8%
which is designed to produce additional annual revenues of approximately $70.7
million based on a test year calculation. The SCPSC authorized a return on
common equity of 12.45%. The new rates were effective for service rendered on
and after February 1, 2003. As a part of the order, the SCPSC extended through
2005 its approval of the accelerated capital recovery plan for SCE&G's Cope
Generating Station. Under the plan, based on the level of revenues and operating
expenses, SCE&G may increase depreciation of its Cope Generating Station in
excess of amounts that would be recorded based upon currently approved
depreciation rates, not to exceed $36 million annually without the approval of
the SCPSC. Any unused portion of the $36 million in any given year may be
carried forward for possible use in the following year.
The following table summarizes how the Company generated and used funds
for property additions and construction expenditures during the three months
ended March 31, 2003 and 2002:
- -----------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------- -------------
Net cash provided from operating activities $144 $181
Net cash provided from financing activities 4 85
Cash provided from sale of investments and assets - 313
Funds used for investments (4) (16)
Cash and temporary investments available at the
beginning of the period 397 212
Funds used for utility property additions and
construction expenditures,
net of noncash allowance for
funds used during construction 171 117
Funds used for nonutility property additions 3 2
CAPITAL TRANSACTIONS
On January 13, 2003 SCANA retired at maturity $60 million of 6.05%
medium-term notes.
On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds
having an annual interest rate of 5.80% and maturing on January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt and
for general corporate purposes.
On April 4, 2003 SCANA redeemed $100 million of floating rate
medium-term notes that were set to mature August 8, 2003. The notes were bearing
interest at a rate of 2.215% when redeemed.
CAPITAL PROJECTS
In May 2002 SCE&G began construction of an 875 megawatt generation
facility in Jasper County, South Carolina to supply electricity to its South
Carolina customers. The facility will include three natural gas
combustion-turbine generators and one steam-turbine generator. The $450 million
facility is expected to begin commercial operation in mid-2004. SCG will
transport natural gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam
in order to comply with new federal safety standards and maintain the lake in
case of an extreme earthquake. Construction for the project and related
activities, which began in the third quarter of 2001, is expected to cost
approximately $275 million and be completed in 2005. Costs incurred through
March 31, 2003 totaled approximately $83 million.
In 2002 SCE&G entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to
construct a roadbed for SCDOT in connection with the above Lake Murray dam
remediation project. The loan agreement provides for interest-free borrowings
for costs incurred not to exceed $59 million, with such borrowings being repaid
over ten years from the initial borrowing. At March 31, 2003 SCE&G has not
borrowed under the agreement.
ENVIRONMENTAL MATTERS
For information on environmental matters see Note 7C of Notes to
Condensed Consolidated Financial Statements.
OTHER MATTERS
Nuclear Station License Extension
In August 2002 SCE&G filed an application with the Nuclear Regulatory
Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear
Station (Summer Station). If approved, the extension would allow the plant to
operate through 2042. SCE&G estimates that it will incur approximately $12
million in costs related to the application process. SCE&G expects the extension
to be issued in mid-2004.
Telecommunications Investments
On May 9, 2003, the Company's investment in ITC Holding Company. Inc. was
sold. The sale resulted in the receipt of net after-tax cash proceeds of
approximately $40 million and the receipt of an investment interest in a newly
formed entity valued at approximately $15 million. A book gain, net of tax, of
approximately $40 million was realized upon this sale.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2003
AS COMPARED TO THE CORRESPONDING PERIOD IN 2002
The following discussion of the Company's results of operations
includes a non-GAAP measure, net earnings from operations per share, which
excludes from net income (loss) (i) the cumulative effects of mandated changes
in accounting principles and (ii) the effects of sales of certain investments
and impairment charges related to certain investments. Management considers net
earnings from operations to be a relevant measure in assessing the Company's
fundamental earnings in that it provides investors with improved transparency of
financial information and more meaningful comparability of period-over-period
analysis.
Earnings Per Share
Net earnings from operations (loss) per share of common stock for the
three months ended March 31, 2003 and 2002 were as follows:
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
2003 2002
- ----------------------------------------------------------------------- --------
Earnings (loss) per share $.75 $(2.88)
Less: Realized gain from sale of investment - .10
Investment impairments - (1.52)
Cumulative effect of accounting change, net of taxes - (2.20)
- ------------------------------------------------------------------------ -------
Net earnings from operations per share $.75 $.74
========================================================================= ======
Net earnings from operations per share increased $.01 primarily due to
improved electric margins of $.13 and improved gas margins of $.12. These
factors were offset by higher operation and maintenance expenses of $.10, higher
property taxes of $.02, higher depreciation and amortization expense of $.04,
the dilutive effect of the change in shares outstanding of $.05, lower allowance
for funds used during construction (AFC) of $.02 and other of $.01.
Prior year net earnings from operations per share includes a gain of
$.10 per share in connection with the sale of Deutsche Telekom AG (DTAG) shares
in March 2002. In March 2002 the Company also recorded an impairment write-down
of $1.52 per share related to the other than temporary decline in market value
of the Company's investment in DTAG. Also, as required by SFAS 142 the Company
recorded an impairment charge of $2.20 per share, effective January 1, 2002,
related to the acquisition adjustment associated with Public Service Company of
North Carolina, Incorporated (PSNC Energy). The charge was recorded as the
cumulative effect of an accounting change.
Pension Income
For the last several years, the market value of the Company's retirement
plan (pension) assets has exceeded the total actuarial present value of
accumulated plan benefits. However, pension income in the first quarter of 2003
decreased significantly compared to corresponding period in 2002 primarily as a
result of a less favorable investment market. Pension income during these
periods was recorded on the Company's financial statements as follows:
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------- ---------------
- --------------------------------------------------------------- ---------------
Income Statement Impact:
(Increase) decrease in employee benefit costs $(1.0) $3.6
Increase in other income 1.9 2.0
Balance Sheet Impact:
(Increase) decrease in capital expenditures (0.3) 1.0
Decrease in amount due to Santee Cooper - 0.3
- --------------------------------------------------------------- ---------------
- --------------------------------------------------------------- ---------------
Total Pension Income $0.6 $6.9
=============================================================== ===============
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of
both equity and borrowed funds used to finance construction (which is shown on
the balance sheet as construction work in progress) is capitalized. 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. AFC represented approximately 5% and
8% of income before income taxes, gains, impairments and the cumulative effect
of an accounting change for the three months ended March 31, 2003 and 2002,
respectively. The decrease in AFC is primarily the result of the completion of
the Urquhart Station repowering project in June 2002. In addition, in January
2003 the SCPSC issued an order allowing SCE&G to include all Jasper County
Generating project expenditures as of December 31, 2002 and other construction
work in progress expenditures as of June 30, 2002 in electric rate base. At the
time the expenditures were included in rate base, AFC was no longer calculated
on those amounts. These decreases were partially offset by increased
construction expenditures related to the Jasper County Generating Station
project in 2003 and the Lake Murray Dam project (see discussion CAPITAL
PROJECTS).
Dividends Declared
The Company's Board of Directors declared the following dividends on
common stock during 2003 :
- ------------------- ----------------------- --------------------- --------------
Declaration Date Dividend Per Share Record Date Payment Date
- ------------------- ----------------------- --------------------- --------------
February 20, 2003 $.345 March 10, 2003 April 1, 2003
May 1, 2003 $.345 June 10, 2003 July 1, 2003
- ------------------- ----------------------- --------------------- --------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G, South
Carolina Generating Company (GENCO) and South Carolina Fuel Company (Fuel
Company). Changes in the electric operations sales margins were as follows:
------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
------------------------------------------------------------------------------
------------------------------------------------------------------------------
Operating revenues $336.0 $302.6 $33.4 11.0%
Less: Fuel used in generation 80.8 74.3 6.5 8.7%
Purchased power 10.5 5.0 5.5 *
------------------------------------------------------------------
Margin $244.7 $223.3 $21.4 9.6%
==============================================================================
*Greater than 100%
Margin increased by $8.8 million due to the increase in retail electric
base rates approved in January 2003, by $5.6 million due to more favorable
weather and by $7.0 million due to customer growth. Fuel used in generation
increased primarily due to completion of the Urquhart Station repowering project
in June 2002. Purchased power increased due to several planned outages at steam
plants during the first quarter of 2003.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC Energy. Changes in the gas distribution sales margins, including
transactions with affiliates, were as follows:
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Operating revenues $343.3 $241.0 $102.3 42.4%
Less: Gas purchased for resale 231.5 140.1 91.4 65.2%
- --------------------------------------------------------------------
Margin $111.8 $100.9 $10.9 10.8%
===============================================================================
Margin increased primarily due to increased customer growth at PSNC
Energy (3.5%) and SCE&G (2.0%), increased recovery of environmental remediation
expenses of $1.3 million (offset in operations and maintenance) and more
favorable weather.
Gas Transmission
Gas Transmission is comprised of the operations of SCPC. Changes in the
gas transmission sales margins, including transactions with affiliates, were as
follows:
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
Operating revenues $192.4 $128.1 $64.3 50.2%
Less: Gas purchased for resale 179.4 128.5 50.9 39.6%
- --------------------------------------------------------------------
Margin $13.0 $(0.4) $13.4 *
===============================================================================
*Greater than 100%
Margin increased primarily due to the favorable competitive position of
natural gas relative to alternate fuels.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy. Retail Gas Marketing
revenues and net income, were as follows:
- ------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
- ------------------------------------------------------------------------------
Operating revenues $183.7 $156.2 $27.5 17.6%
Net income (loss) 13.2 13.7 (3.6%)
(0.5)
==============================================================================
Operating revenues increased primarily as a result of the increase in
average retail price and higher volumes. Net income decreased slightly primarily
due to higher interest expense of $0.3 million and higher operating expense of
$0.6 million partially offset by higher margins of $0.6 million.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Changes in energy marketing operating
revenues, including transactions with affiliates, and net loss were as follows:
- ------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
- ------------------------------------------------------------------------------
Operating revenues $122.4 $67.8 $54.6 80.5%
Net loss (1.8) (1.0) (0.8) (80.0%)
==============================================================================
Operating revenues increased primarily as a result of the increase in
commodity natural gas prices. Net loss increased primarily as a result of lower
margins of $2.6 million partially offset by lower interest and bad debt expense
of $1.5 million.
Other Operating Expenses
Changes in other operating expenses were as follows:
- ------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
- ------------------------------------------------------------------------------
Other operation and maintenance $144.1 $126.4 $17.7 14.0%
Depreciation and amortization 59.9 53.8 6.1 11.3%
Other taxes 34.5 31.2 3.3 10.6%
- -------------------------------------------------------------------
Total $238.5 $211.4 $27.1 12.8%
==============================================================================
Other operation and maintenance expenses increased primarily due to
reduced pension income of $4.6 million, increased labor and benefits costs of
$5.3 million, increased healthcare cost of $2.4 million, increased amortization
of environmental costs of $1.3 million and increased other operating expenses
for electric generation and transmission of $5.6 million. Depreciation and
amortization increased by $3.6 million due to normal net property changes and by
$2.5 million due to the completion of the Urquhart Station repowering project in
June 2002. Other taxes increased primarily due to increased property taxes.
Other Income (Loss)
Other income, including AFC, increased primarily due to changes related
to the gain on sale of investments and assets and the impairment of investments
as discussed at Earnings Per Share partially offset by a reduction in AFC due to
the SCPSC order allowing SCE&G to include all Jasper County Generating project
expenditures as of December 31, 2002 and other construction work in progress
expenditures as of June 30, 2002 in electric rate base.
Interest Expense
Interest expense decreased due to lower interest rates ($1.8 million),
partially offset by $0.6 million due to increased debt and lower AFC.
Income Taxes
Income taxes increased primarily as a result of changes in Other Income
(Loss) as discussed at Earnings Per Share.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about long-term
debt issued by the Company and other financial instruments that are sensitive to
changes in interest rates. For debt obligations the table presents principal
cash flows and related weighted average interest rates by expected maturity
dates. For interest rate swaps, the figures shown reflect notional amounts and
related maturities. Fair values for debt and swaps represent quoted market
prices.
As of March 31, 2003 Expected Maturity Date
- -------------------- ----------------------
Millions of dollars
There- Fair
Liabilities 2003 2004 2005 2006 2007 after Total Value
- --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- --------------
- --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- --------------
Long-Term Debt:
Fixed Rate ($) 252.9 202.1 197.0 177.3 71.3 2,374.2 3,274.8 3,467.0
Average Fixed Interest Rate (%) 7.55 7.51 7.37 8.52 6.94 6.65 6.92
Variable Rate ($) 100.0 150.0 250.0 249.3
Average Variable Interest Rate (%) 2.22 1.97 2.07
Interest Rate Swaps:
Pay Variable/Receive Fixed ($) 7.5 57.5 3.2 3.2 28.2 241.0 340.6 11.69
Average Pay Interest Rate (%) 6.07 5.97 4.48 4.48 4.44 2.96 3.69
Average Receive Interest Rate (%) 9.47 7.70 8.75 8.75 7.11 6.21 6.65
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, 2003 the Company held investments in the 12% senior unsecured
notes (due 2009) of a telecommunications company, the cost basis of which,
including accrued interest, is approximately $45 million. As these notes are not
actively traded, determination of their fair value is not practicable.
Commodity price risk - The following table provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value
represents quoted market prices.
As of March 31, 2003
Millions of dollars, except weighted average settlement price and strike price
Natural Gas Derivatives: Expected Maturity in 2003 Expected Maturity in 2004 Expected Maturity in 2005
- ----------------------------
- ---------------------------- ----------- ---------- ----------- ----------- ---------- ---------- ------------ ------------ --------
Settlement Contract Fair Settlement Contract Fair Settlement Contract Fair
Price (a) Amount Value Price (a) Amount Value Price (a) Amount Value
Futures Contracts:
Long($) 5.12 12.3 12.8 4.74 3.1 3.1 4.30 2.7 2.7
Short($) 5.10 1.6 2.0 - - - - - -
Strike Contract
Price Amount
(a)
Options:
Purchased call (long)($) 5.08 9.4
Sold call (short) ($) 3.94 1.8
- ---------------------------- ----------- ---------- ----------- -------------- ------------ ----------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
(a) Weighted average
The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of different types. See Note 6
of Notes to Condensed Consolidated Financial Statements.
The NYMEX futures information above includes those financial positions
of both Energy Marketing and SCPC. Certain derivatives that SCPC utilizes to
hedge its gas purchasing activities are recoverable through its weighted average
cost of gas calculation. SCPC's tariffs include a purchased gas adjustment (PGA)
clause that provides for the recovery of actual gas costs incurred. The SCPSC
has ruled that the results of SCPC's hedging activities are to be included in
the PGA. The offset to the change in fair value of these derivatives is recorded
as a current asset or liability.
Beginning in January 2003, PSNC Energy initiated a hedging program for gas
purchasing activities using NYMEX futures and options. PSNC Energy's tariffs
include a provision for the recovery of actual gas costs incurred. PSNC Energy
will include the offset to the change in fair value of derivatives acquired as
part of its hedging program in deferred accounts for the over or under recovery
of gas costs. PSNC Energy will seek approval of this accounting and cost
recovery treatment from the North Carolina Utilities Commission (NCUC) during
the annual review of its gas purchasing practices in 2003. The offset to the
change in fair value of these derivatives will be recorded as a regulatory asset
or liability.
Equity price risk - Investments in telecommunications companies' equity
securities (excluding preferred stock with significant debt characteristics) are
carried at market value or, if market value is not readily determinable, at
cost. The carrying value of the Company's investments in such securities totaled
$108.7 million at March 31, 2003. A temporary decline in value of ten percent
would result in a $10.9 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 $10.9 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, 2003 an evaluation was performed under the supervision
and with the participation of the Company's management, including the Chief
Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness
of the design and operation of the Company's disclosure controls and procedures.
Based on that evaluation, the Company's management, including the CEO and CFO,
concluded that as of March 31, 2003 the Company's disclosure controls and
procedures were effective. There have been no significant changes in the
Company's internal controls or in other factors that could significantly affect
internal controls subsequent to March 31, 2003.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
Item 1. Financial Statements
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Assets
Utility Plant:
Electric 5,031 $4,934
Gas 442 439
Other 186 184
- --------------------------------------------------------------------------------
Total 5,659 5,557
Accumulated depreciation and amortization (1,960) (1,912)
- --------------------------------------------------------------------------------
Total 3,699 3,645
Construction work in progress 684 604
Nuclear fuel, net of accumulated amortization 32 38
- --------------------------------------------------------------------------------
Utility Plant, Net 4,415 4,287
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 26 25
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 68 79
Receivables 247 245
Receivables - affiliated companies 2 2
Inventories (at average cost):
Fuel 37 48
Materials and supplies 51 53
Emission allowances 9 10
Prepayments 20 24
- --------------------------------------------------------------------------------
Total Current Assets 434 461
- --------------------------------------------------------------------------------
Deferred Debits:
Environmental 14 18
Nuclear plant decommissioning - 87
Assets held in trust, net - nuclear
decommissioning 50 -
Pension asset, net 266 265
Due from affiliates - pension
and postretirement benefits 19 18
Due from affiliates 51 36
Other regulatory assets 257 244
Other 115 111
- --------------------------------------------------------------------------------
Total Deferred Debits 772 779
- --------------------------------------------------------------------------------
Total $5,647 $5,552
================================================================================
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $1,976 $1,966
Preferred stock (Not subject to purchase
or sinking funds) 106 106
- --------------------------------------------------------------------------------
Total Stockholders' Investment 2,082 2,072
Preferred Stock, net (Subject to purchase
or sinking funds) 9 9
Company-Obligated Mandatorily Redeemable
Preferred Securities of the Company's
Subsidiary Trust, SCE&G Trust I, holding
solely $50 million principal amount
of 7.55%
Junior Subordinated Debentures of SCE&G, due 202 50 50
Long-Term Debt, net 1,733 1,534
- --------------------------------------------------------------------------------
Total Capitalization 3,874 3,665
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 114 178
Current portion of long-term debt 144 144
Accounts payable 94 132
Accounts payable - affiliated companies 74 69
Customer deposits 23 22
Taxes accrued 53 93
Interest accrued 35 31
Dividends declared 37 42
Deferred income taxes, net 9 12
Other 25 37
- --------------------------------------------------------------------------------
Total Current Liabilities 608 760
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes, net 613 610
Deferred investment tax credits 108 108
Reserve for nuclear plant decommissioning - 87
Asset retirement obligation - nuclear plant 113 -
Due to affiliates - pension and
postretirement benefits 16 17
Postretirement benefits 134 131
Regulatory liabilities 115 109
Other 66 65
- --------------------------------------------------------------------------------
Total Deferred Credits 1,165 1,127
- --------------------------------------------------------------------------------
Total $5,647 $5,552
================================================================================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Operating Revenues:
Electric $338 $304
Gas 140 107
- --------------------------------------------------------------------------------
Total Operating Revenues 478 411
- --------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 69 55
Purchased power (including affiliated purchases) 32 33
Gas purchased for resale 100 73
Other operation and maintenance 101 83
Depreciation and amortization 47 42
Other taxes 30 26
- --------------------------------------------------------------------------------
Total Operating Expenses 379 312
- --------------------------------------------------------------------------------
Operating Income 99 99
Other Income, Including Allowance for Equity Funds
Used During Construction of $4 and $6 6 9
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 105 108
Interest Charges, Net of Allowance for Borrowed
Funds Used During Construction of $2 and $4 32 28
Dividend Requirement of Company -
Obligated Mandatorily Redeemable Preferred Securities 1 1
- --------------------------------------------------------------------------------
Income Before Income Taxes and Preferred Stock Dividends 72 79
Income Taxes 25 27
- --------------------------------------------------------------------------------
Net Income 47 52
Preferred Stock Cash Dividends Declared (At stated rates) 2 2
- --------------------------------------------------------------------------------
Earnings Available for Common Stockholder $45 $50
================================================================================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $47 $52
Adjustments to reconcile net income to net
cash provided from operating activities:
Depreciation and amortization 47 42
Amortization of nuclear fuel 6 5
Allowance for funds used during construction (6) (10)
Over (under) collections, fuel adjustment clauses 22 7
Changes in certain assets and liabilities:
(Increase) decrease in receivables (2) (7)
(Increase) decrease in inventories 14 (8)
(Increase) decrease in prepayments 4 (5)
(Increase) decrease in pension asset (1) (7)
(Increase) decrease in other regulatory assets - 1
Increase (decrease) in deferred income taxes, net - 23
Increase (decrease) in other regulatory liabilitie 9 10
Increase (decrease) in postretirement benefits 3 2
Increase (decrease) in accounts payable (33) (20)
Increase (decrease) in taxes accrued (40) (60)
Increase (decrease) in interest accrued 4 5
Changes in other assets (14) (13)
Changes in other liabilities (5) 8
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 55 25
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures,
net of AFC (139) (103)
Proceeds from sales of assets - 1
Investment in affiliate (15) 1
Investments (4) (1)
- --------------------------------------------------------------------------------
Net Cash Used For Investing Activities (158) (102)
- --------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds from issuance of First Mortgage Bonds 198 295
Repayments:
First and Refunding Mortgage Bonds - (104)
Other long-term debt - (1)
Dividends and distributions:
Common stock (40) (40)
Preferred stock (2) (2)
Short-term borrowings, net (64) (67)
- --------------------------------------------------------------------------------
Net Cash Provided From Financing Activities 92 81
- --------------------------------------------------------------------------------
Net Increase (Decrease) In Cash and Temporary Investments (11) 4
Cash and Temporary Investments, January 1 79 57
- --------------------------------------------------------------------------------
Cash and Temporary Investments, March 31 $68 $61
================================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $2 and $4) $28 $54
- Income taxes - 3
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2003
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in South Carolina Electric & Gas
Company's (the Company) Annual Report on Form 10-K for the year ended December
31, 2002. These are interim financial statements, and due to the seasonality of
the Company's business, the amounts reported in the Condensed Consolidated
Statements of Income are not necessarily indicative of amounts expected for the
year. In the opinion of management, the information furnished herein reflects
all adjustments, all of a normal recurring nature which are necessary for a fair
statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result the Company has
recorded, as of March 31, 2003, approximately $271 million and $115 million of
regulatory assets and liabilities, respectively, as shown below.
March 31, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Accumulated deferred income taxes, net $86 $86
Under-collections - electric fuel
and gas cost adjustment clauses 28 50
Deferred environmental remediation costs 14 18
Asset Retirement Obligation - nuclear decommissioning 36 -
Deferred non-conventional fuel tax benefits, net (45) (40)
Storm damage reserve (33) (32)
Franchise agreements 65 65
Other 5 5
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total $156 $152
================================================================================
Accumulated deferred income taxes represent deferred income tax
liabilities applicable to utility operations that have not been reflected in
customer rates for which future recovery is probable, offset by deferred income
tax assets, which will be reflected in customer rates as a result of reduced
revenue requirements due to the amortization of deferred investment tax credits.
Under-collections - fuel adjustment clauses represent amounts
under-collected from customers pursuant to the fuel adjustment clause
(electric customers) or gas cost adjustment clause (gas customers) as approved
by the Public Service Commission of South Carolina (SCPSC) during annual
hearings.
Deferred environmental remediation costs represent costs associated
with the assessment and clean up of manufactured gas plant (MGP) sites currently
or formerly owned by the Company. Costs incurred at sites owned by the Company
are being recovered through rates, and such costs, totaling approximately $14
million, are expected to be fully recovered by the end of 2005.
Asset Retirement Obligation - nuclear decommissioning represents the
regulatory asset associated with the legal obligation of decommissioning and
dismantling V. C. Summer Nuclear Station (Summer Station) as required in SFAS
143, "Accounting for Asset Retirement Obligations." (See Note 1B).
Deferred non-conventional fuel tax benefits represent the deferral of
partnership losses and other expenses, offset by the accumulated deferred income
tax credits associated with two of the Company's partnerships involved in
converting coal to alternate fuel. Under a plan approved by the SCPSC, any net
tax credits generated from non-conventional fuel produced and consumed by the
Company and ultimately passed through to the Company have been and will be
deferred and will be applied to offset the capital costs of projects required to
comply with legislative or regulatory actions.
The storm damage reserve represents an SCPSC approved reserve account
capped at $50 million to be collected through rates over a ten-year period. The
accumulated storm damage reserve can be applied to offset actual storm damage
costs in excess of $2.5 million in a calendar year.
Franchise agreements represent costs associated with the 30-year
electric and gas franchise agreements with the cities of Charleston and
Columbia, South Carolina. These amounts are not earning a return, but are being
amortized through cost of service over the next 15 years.
The SCPSC has reviewed and approved through specific orders most of the
items shown as regulatory assets. Other items represent costs which are not yet
approved for recovery by the SCPSC. In recording these costs as regulatory
assets, management believes the costs will be allowable under existing
rate-making concepts that are embodied in rate orders received by the Company.
However, ultimate recovery is subject to SCPSC approval. In the future, as a
result of deregulation or other changes in the regulatory environment, the
Company may no longer meet the criteria for continued application of SFAS 71 and
could be required to write off its regulatory assets and liabilities. Such an
event could have a material adverse effect on the Company's results of
operations in the period the write-off would be recorded, but it is not expected
that cash flows or financial position would be materially affected.
B. New Accounting Standards
The Company adopted SFAS 143 effective January 1, 2003. SFAS 143
applies to legal obligations associated with the retirement of tangible
long-lived assets (ARO) and requires the Company to recognize, as a liability,
the fair value of an ARO in the period in which it is incurred and to accrete
the liability to its present value in future periods. As of December 31, 2002,
prior to the adoption of SFAS 143, the Company carried deferred debits and
deferred credits each totaling approximately $87 million related to the
decommissioning and dismantling of Summer Station and the funding thereof.
Effective January 1, 2003, in connection with the measurement of the ARO upon
the adoption of SFAS 143, the amounts reflected within these regulatory assets
and liabilities were recharacterized.
The following table presents such recharacterized amounts related to the
decommissioning obligation and the funding thereof as recorded in the
consolidated balance sheet as of March 31, 2003 and the pro forma amounts that
would have been recorded as of December 31, 2002 had SFAS 143 been adopted at
the beginning of 2002.
As of
March 31, December 31,
2003 2002
Actual Proforma
Assets:
Within electric plant $40 $40
Within accumulated depreciation (13) (13)
Assets held in trust (net) - nuclear
decommissioning 50 50
Within other regulatory assets 36 34
------------ -------------
------------ -------------
Total $113 $111
============ =============
============ =============
Liabilities:
Asset retirement obligation - nuclear
plant decommissioning $113 $111
============ =============
Proforma net income (loss) for periods prior to the adoption of SFAS
143 would not differ from amounts actually recorded during these periods.
In addition to the ARO for Summer Station, the Company believes that
there is legal uncertainty as to the existence of environmental obligations
associated with certain transmission and distribution properties. The Company
believes that any ARO related to this type of property would be insignificant
and, due to the indeterminate life of the related assets, an ARO could not be
reasonably estimated.
The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. The provisions of SFAS 145, among other things,
discontinue treatment of gains or losses from the early extinguishment of debt
as extraordinary items unless such early extinguishment meets the criteria of
Accounting Principles Board Opinion (APB) 30. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. This statement requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2003.
2. RATE AND OTHER REGULATORY MATTERS
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the
level of revenues and operating expenses, SCE&G may increase depreciation of its
Cope Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates, not to exceed $36 million annually,
without the approval of the SCPSC. Any unused portion of the $36 million in any
given year may be carried forward for possible use in the following year.
In May 2002 the SCPSC issued an order approving SCE&G's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for under-collected actual fuel costs through April 2001,
including short-term purchased power costs necessitated by outages at two of
SCE&G's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002. The Consumer Advocate of
South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the
portion of the SCPSC's order related to the recovery of certain purchased power
costs. The appeal is still pending.
In January 2003, in conjunction with the approval of the above retail
rate increase, the SCPSC approved SCE&G's request to reduce the fuel component
to 1.678 cents per KWh. This reduction was effective for service rendered on and
after February 1, 2003. In April 2003 the SCPSC issued an order approving
SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per
KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's
purchasing practices and recognized the efficiency of SCE&G's electric
generating plants; however, it deferred action on the recovery of certain
purchased power costs pending the appeal to the Circuit Court of the SCPSC's May
2002 order.
Gas
The Company's rates are established using a cost of gas component
approved by the SCPSC which may be modified periodically to reflect changes in
the price of natural gas purchased by the Company.
The Company's cost of gas component in effect during the period January
1, 2002 through March 31, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002
$.928 March 2003 $.728 November-December 2002
The SCPSC allows the Company to recover, through a billing surcharge to
its gas customers, the costs of environmental cleanup at the sites of former
manufactured gas plants (MGPs). The billing surcharge is subject to annual
review and provides for the recovery of substantially all actual and projected
site assessment and cleanup costs and environmental claims settlements for the
Company's gas operations that had previously been recorded in deferred debits.
In October 2002, as a result of the annual review, the SCPSC reaffirmed the
Company's billing surcharge of 3.0 cents per therm, which is intended to provide
for the recovery, prior to the end of the year 2005, of the balance remaining at
March 31, 2003 of $13.6 million.
3. LONG-TERM DEBT
On January 23, 2003 the Company issued $200 million of First Mortgage
Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033.
The proceeds from the sale of these bonds were used to reduce short-term debt
and for general corporate purposes.
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, 2003 approximately $41.5 million of retained earnings
were restricted by this requirement as to payment of cash dividends on common
stock.
5. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 11 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002. Commitments and Contingencies at March 31, 2003 include
the following:
A. Lake Murray Dam Reinforcement
In October 1999 the United States Federal Energy Regulatory Commission
(FERC) mandated that the Company reinforce its Lake Murray dam in order to
comply with new federal safety standards and maintain the lake in case of an
extreme earthquake. Construction for the project and related activities, which
began in the third quarter of 2001, is expected to cost approximately $275
million and be completed in 2005. Costs incurred through March 31, 2003 totaled
approximately $83 million.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public
liability for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 million of the liability per reactor would be
assessed per year. The Company's maximum assessment, based on its two-thirds
ownership of Summer Station, would be approximately $58.7 million per incident,
but not more than $6.7 million per year.
The Price-Anderson Indemnification Act expired in August 2002, but is
expected to renew with only modest changes in 2003. This has no impact on the
Company at present due to the "grandfathered" status of existing licensees that
are covered under the past act until such time as it is renewed.
The Company currently maintains policies (for itself and on behalf of
Santee Cooper) with Nuclear Electric Insurance Limited. The policies, covering
the nuclear facility for property damage, excess property damage and outage
costs, permit assessments under certain conditions to cover insurer's losses.
Based on the current annual premium, the Company's portion of the retrospective
premium assessment would not exceed $15.5 million.
To the extent that insurable claims for property damage, decontamination,
repair and replacement and other costs and expenses arising from a nuclear
incident at Summer Station exceed the policy limits of insurance, or to the
extent such insurance becomes unavailable in the future, and to the extent that
the Company's rates would not recover the cost of any purchased replacement
power, the Company will retain the risk of loss as a self-insurer. The Company
has no reason to anticipate a serious nuclear incident at Summer Station. If
such an incident were to occur, it would have a material adverse impact on the
Company's results of operations, cash flows and financial position.
C. Environmental
The Company maintains an environmental assessment program to identify and
evaluate current and former operations sites that could require environmental
cleanup. As site assessments are initiated, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate solely to regulated operations.
At the Company, site assessment and cleanup costs are deferred and
amortized with recovery provided through rates. Deferred amounts, net of amounts
previously recovered through rates and insurance settlements, totaled $13.6
million at March 31, 2003. The deferral includes the estimated costs associated
with the following matters.
The Company owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. SCE&G
anticipates that the remaining remediation activities will be completed in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
March 31, 2003, the Company has spent approximately $18.6 million to remediate
the Calhoun Park site. Total remediation costs are estimated to be $21.9
million.
The Company owns three other decommissioned MGP sites in South Carolina
which contain residues of by-product chemicals. Two of these sites are currently
being remediated under work plans approved by DHEC. 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 these three sites will be completed before 2006. The Company has
spent approximately $2.3 million related to these sites, and expects to spend an
additional $5.8 million.
In addition, in March 2003 the Company signed a consent agreement with
DHEC related to a site formerly owned by the Company. The estimated cost for
remediation of this site has not been finalized but it is not expected to be
material.
6. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The
Company uses operating income to measure profitability for its regulated
operations. Therefore, net income is not allocated to the Electric Operations
and Gas Distribution segments. Accumulated depreciation is not assignable to
Electric Operations and Gas Distribution segments. Intersegment revenues were
not significant.
Disclosure of Reportable Segments
(Millions of Dollars)
- -------------------------------------------- ---------------- -----------------
Three months ended External Operating Segment
March 31, 2003 Revenue Income (Loss) Assets
- -------------------------------------------- ---------------- -----------------
Electric Operations $338 $81 $5,673
Gas Distribution 140 18 449
All Other - - -
Adjustments/Eliminations - - (475)
- -------------------------------------------- ---------------- -----------------
- -------------------------------------------- ---------------- -----------------
Consolidated Total $478 $99 $5,647
============================================ ================ =================
- ------------------------------------------- ---------------- -----------------
Three months ended External Operating Segment
March 31, 2002 Revenue Income (Loss) Assets
- ------------------------------------------- ---------------- -----------------
Electric Operations $304 $84 $5,124
Gas Distribution 107 16 431
All Other - - -
Adjustments/Eliminations - (1) (496)
- ------------------------------------------- ---------------- -----------------
- ------------------------------------------- ---------------- -----------------
Consolidated Total $411 $99 $5,059
=========================================== ================ =================
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- --------------------------------------------------------------------------------
SOUTH CAROLINA ELECTRIC & GAS COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with
Management's Discussion and Analysis of Financial Condition and Results of
Operations appearing in South Carolina Electric & Gas Company's (SCE&G) Annual
Report on Form 10-K for the year ended December 31, 2002.
Statements included in this discussion and analysis (or elsewhere in
this quarterly report) which are not statements of historical fact are intended
to be, and are hereby identified as, "forward-looking statements" for purposes
of the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, (3) changes in the economy, especially in SCE&G's service
territory, (4) the impact of competition from other energy suppliers, (5) growth
opportunities, (6) the results of financing efforts, (7) changes in SCE&G's
accounting policies, (8) weather conditions, especially in areas served by
SCE&G, (9) performance of SCANA Corporation's pension plan assets and the impact
on SCE&G's results of operations, (10) inflation, (11) changes in environmental
regulations and (12) the other risks and uncertainties described from time to
time in SCE&G's periodic reports filed with the United States Securities and
Exchange Commission (SEC). SCE&G disclaims any obligation to update any
forward-looking statements.
COMPETITION
Electric Operations
In South Carolina, electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2003. At the
federal level, the House of Representatives has passed the Energy Policy Act of
2003, and the Senate is expected to approve similar legislation. Some of the
more stringent provisions of this legislation, either currently included or
expected to be debated in conference committee, would require that one percent
of the electric energy sold by retail electric suppliers, beginning in 2005,
escalating to ten percent by 2020, be generated from renewable energy resources.
Renewable energy resources, as defined in the legislation, may exclude
hydroelectric generation. Substantial penalties would be levied for failure to
comply. Electric cooperatives and municipal utilities would be exempt from these
requirements. The Company cannot predict whether such legislation will be
enacted, and if it is, the conditions it would impose on utilities.
In July 2002 the United States Federal Energy Regulatory Commission
(FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design
(SMD) which proposes sweeping changes to the country's existing regulatory
framework governing transmission, open access and energy markets and will
attempt, in large measure, to standardize the national energy market. If
implemented, the proposed rule may have a significant impact on SCE&G's access
to or cost of power for its native load customers and on SCE&G's marketing of
power outside its service territory. On April 28, 2003, FERC issued a "white
paper" regarding SMD which describes how the final SMD rule will differ from the
NOPR. SCE&G is currently evaluating FERC's actions to determine potential
effects on SCE&G's operations. Additional directives from FERC are expected.
Gas Distribution
Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, the other household energy needs of
residential and small commercial customers. This competition is generally based
on price and convenience. Large commercial and industrial customers often have
the ability to switch from natural gas to an alternate fuel, such as propane or
fuel oil. Natural gas competes with these alternate fuels based on price. As a
result, any significant disparity between supply and demand, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect the price and impact SCE&G's ability to retain
large commercial and industrial customers on a monthly basis.
LIQUIDITY AND CAPITAL RESOURCES
SCE&G's cash requirements arise primarily from its operational needs,
funding its construction program and payment of dividends to SCANA. The ability
of SCE&G to replace existing plant investment, as well as to expand to meet
future demand for electricity and gas, will depend upon its ability to attract
the necessary financial capital on reasonable terms. SCE&G recovers the costs of
providing services through rates charged to customers. Rates for regulated
services are generally based on historical costs. As customer growth and
inflation occur and SCE&G continues its ongoing construction program, SCE&G
expects to seek increases in rates. SCE&G's future financial position and
results of operations will be affected by its ability to obtain adequate and
timely rate and other regulatory relief, if requested.
In January 2003 the Public Service Commission of South Carolina (SCPSC)
issued an order granting SCE&G an increase in retail electric rates of 5.8%
which is designed to produce additional annual revenues of approximately $70.7
million based on a test year calculation. The SCPSC authorized a return on
common equity of 12.45%. The new rates were effective for service rendered on
and after February 1, 2003. As a part of the order, the SCPSC extended through
2005 its approval of the accelerated capital recovery plan for SCE&G's Cope
Generating Station. Under the plan, based on the level of revenues and operating
expenses, SCE&G may increase depreciation of its Cope Generating Station in
excess of amounts that would be recorded based upon currently approved
depreciation rates, not to exceed $36 million annually without the approval of
the SCPSC. Any unused portion of the $36 million in any given year may be
carried forward for possible use in the following year.
The following table summarizes how SCE&G generated and used funds for
property additions and construction expenditures during the three months ended
March 31, 2003 and 2002:
- -----------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- ---------------------------------------------------------------- ------------
Net cash provided from operating activities $55 $25
Net cash provided from financing activities 92 81
Funds used for investments (4) (1)
Cash and temporary cash investments
available at the beginning of the period 79 57
Funds used for utility property additions
and construction expenditures, net of
noncash allowance for funds used during
construction 139 103
SCE&G expects that it has or can obtain adequate sources of financing to
meet its projected cash requirements for the next 12 months and for the
foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months
ended March 31, 2003 was 3.37.
CAPITAL TRANSACTIONS
On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds
having an annual interest rate of 5.80% and maturing January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt and
for general corporate purposes.
CAPITAL PROJECTS
In May 2002 SCE&G began construction of an 875 megawatt generation
facility in Jasper County, South Carolina to supply electricity to its South
Carolina customers. The facility will include three natural gas
combustion-turbine generators and one steam-turbine generator. The $450 million
facility is expected to begin commercial operation in mid-2004, and SCG
Pipeline, Inc., an affiliate, will transport natural gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam
in order to comply with new federal safety standards and maintain the lake in
case of an extreme earthquake. Construction for the project and related
activities, which began in the third quarter of 2001, is expected to cost
approximately $275 million and be completed in 2005. Costs incurred through
March 31, 2003 totaled approximately $83 million.
In 2002 SCE&G entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to
construct a roadbed for SCDOT in connection with the above Lake Murray dam
remediation project. The loan agreement provides for interest-free borrowings
for costs incurred not to exceed $59 million, with such borrowings being repaid
over ten years from the initial borrowing. At March 31, 2003 SCE&G has not yet
borrowed under the agreement.
Environmental Matters
For information on environmental matters see Note 5C of Notes To
Condensed Consolidated Financial Statements.
Other Matters
Nuclear Station License Extension
In August 2002 SCE&G filed an application with the Nuclear Regulatory
Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear
Station (Summer Station). If approved, the extension would allow the plant to
operate through 2042. SCE&G estimates that it will incur approximately $12
million in costs related to the application process. SCE&G expects the extension
to be granted in mid-2004.
Off-Balance Sheet Arrangement
During the formation of South Carolina Generating Company, Inc. (GENCO)
(a wholly owned subsidiary of SCANA) in 1994, SCE&G's $36 million Berkeley
County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were
transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition,
holders of Berkeley Bonds may have recourse against SCE&G in the event of
default by GENCO.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2003
AS COMPARED TO THE CORRESPONDING PERIOD IN 2002
Net Income
Net income for the three months ended March 31, 2003 and 2002 was as
follows:
- ------------------------------ -------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
- ------------------------------ ---------- -------- -----------------
Net income $47.0 $52.0 ($5.0) (9.6%)
- ------------------------------ ---------- -------- -------- --------
Net income decreased primarily due to higher operation and maintenance
expense of $16.8 million, higher depreciation expense of $5.7 million, higher
interest expense of $2.6 million, higher property taxes of $3.3 million and
lower AFC of $3.3 million, which were partially offset by higher electric
margins of $20.9 million and higher gas margins of $5.5 million.
Pension Income
For the last several years, the market value of SCE&G's retirement plan
(pension) assets has exceeded the total actuarial present value of accumulated
plan benefits. Pension income for the first quarter of 2003 decreased
significantly compared to corresponding periods in 2002 primarily as a result of
a less favorable investment market. Pension income during these periods was
recorded on SCE&G's financial statements as follows:
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- ---------------------------------------------------------------- ---------------
- ---------------------------------------------------------------- ---------------
Income Statement Impact:
(Increase) Decrease in employee benefit costs $(0.7) $3.4
Increase in other income 2.0 2.0
Balance Sheet Impact:
(Increase) Decrease in capital expenditures (0.2) 1.0
(Increase) Decrease in amount due to Santee Cooper - 0.3
- ---------------------------------------------------------------- ---------------
- ---------------------------------------------------------------- ---------------
Total Pension Income $1.1 $6.7
================================================================ ===============
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. AFC represented approximately 8% and
12% of income before income taxes for the three months ended March 31, 2003 and
2002, respectively. The decrease in AFC is primarily the result of the
completion of the Urquhart Station repowering project in June 2002. In addition,
in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper
County Generating project expenditures as of December 31, 2002 and other
construction work in progress expenditures as of June 30, 2002 in electric rate
base. At the time the expenditures were included in rate base, AFC was no longer
calculated on those amounts. These decreases were partially offset by increased
construction expenditures related to the Jasper County Generating Station
project in 2003 and the Lake Murray Dam project (see discussion at CAPITAL
PROJECTS).
Dividends Declared
SCE&G's Board of Directors declared the following dividends on
common stock held by SCANA during 2003:
- -------------------- ------------------ ------------------ ---------------------
Declaration Date Amount Quarter Ended Payment Date
- -------------------- ------------------ ------------------ ---------------------
February 20, 2003 $35.3 million March 31, 2003 April 1, 2003
May 1, 2003 $36.5 million June 30, 2003 July 1, 2003
- -------------------- ------------------ ------------------ ---------------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and
South Carolina Fuel Company. Changes in the electric operations sales margins
were as follows:
-------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
--------------------------------------- ----------- ---------------------
Operating Revenues $337.4 $304.3 $33.1 10.9%
Less: Fuel used in generation 69.1 55.4 13.7 24.7%
Purchased power 31.4 32.9 (4.6%) (1.5)
-------------------------------- ---------
------- -----------
Margin $236.9 $216.0 $20.9 9.7%
======================================= =========== ========= ===========
Margin increased by $8.8 million due to the increase in retail electric
base rates approved in January 2003, by $5.6 million due to more favorable
weather and by $7.0 million due to customer growth. Fuel used in generation
increased primarily due to completion of the Urquhart Station repowering project
in June 2002. Purchased power increased due to several steam plant planned
outages during the first quarter of 2003.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Changes in the gas distribution sales margins were as follows:
-------------------------------------- --------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
----------------------------------------- ----------- ---------------------
Operating Revenues $140.1 $107.1 $33.0 30.8%
Less: Gas purchased for resale 100.2 72.7 27.5 37.8%
---------------------------------- ---------
------- -----------
Margin $39.9 $34.4 $5.5 16.0%
========================================= =========== ========= ===========
Margin increased primarily due to increased recovery of environmental
remediation expenses of $1.3 million (offset in operations and maintenance) and
increased customer growth of 2%.
Other Operating Expenses
Changes in other operating expenses were as follows:
---------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002 Change
----------------------------------------- ----------- ---------------------
Other operation and maintenance $100.9 $82.8 $18.1 21.9%
Depreciation and amortization 47.3 41.5 5.8 14.0%
Other taxes 29.9 26.5 3.4 12.8%
---------------------------------- ---------
------- -----------
Total $178.1 $150.8 $27.3 18.1%
========================================= =========== ========= ===========
Other operation and maintenance expenses increased primarily due to
reduced pension income of $4.0 million, increased labor and benefits costs of
$2.9 million, increased healthcare cost of $2.4 million, increased amortization
of environmental costs of $1.3 million and increased other operating expenses
for electric generation and transmission of $5.6 million. Depreciation and
amortization expense increased by $3.3 million due to normal net property
changes and by $2.5 million due to the completion of the Urquhart Station
repowering project in June 2002. Other taxes increased primarily due to
increased property taxes.
Other Income
Other income, including AFC, decreased primarily due to completion of the
Urquhart Station Repowering project in June 2002. In addition, in January 2003
the SCPSC issued an order allowing SCE&G to include all Jasper County Generating
Project expenditures as of December 31, 2002 and other construction work in
progress expenditures as of June 30, 2002 in electric rate base. At the time the
expenditures were included in rate base, AFC was no longer calculated on those
amounts. These decreases were partially offset by the Jasper County Generation
Station project and Lake Murray Dam Project.
Interest Expense
Interest expense increased primarily due to increased long-term debt of
$4.7 million and lower AFC of $1.2 million partially offset by lower interest
rates of $2.3 million.
Income Taxes
Income taxes changed primarily as a result of changes in operating income.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about long-term
debt issued by SCE&G which is sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates. Fair values for debt represent quoted
market prices.
As of March 31, 2003
Millions of dollars Expected Maturity Date
There- Fair
Liabilities 2003 2004 2005 2006 2007 after Total Value
- ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- --------------
- ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- --------------
Long-Term Debt:
Fixed Rate ($) 144.0 138.4 188.4 169.1 38.2 1,380.6 2,058.7 2,082.1
Average Interest Rate (%) 6.37 7.44 7.35 8.49 6.74 6.66 6.91
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, 2003 an evaluation was performed under the supervision and
with the participation of SCE&G's management, including the Chief Executive
Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the
design and operation of SCE&G's disclosure controls and procedures. Based on
that evaluation, SCE&G's management, including the CEO and CFO, concluded that
as of March 31, 2003 SCE&G's disclosure controls and procedures were effective.
There have been no significant changes in SCE&G's internal controls or in other
factors that could significantly affect internal controls subsequent to March
31, 2003.
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-K and therefore is
filing this form with the reduced disclosure format allowed under General
Instruction H(2).
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
--------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
Assets
Gas Utility Plant $905 $895
Accumulated depreciation (326) (318)
Acquisition adjustment, net of accumulated amortization 210 210
- --------------------------------------------------------------------------------
Gas Utility Plant, Net 789 787
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 27 28
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 6 1
Restricted cash and temporary investments 7 7
Receivables (net of allowance for uncollectible
accounts of $3 and $2) 101 98
Receivables-affiliated companies 17 14
Inventories (at average cost):
Stored gas 19 38
Materials and supplies 5 6
Prepayments 1 1
Deferred income taxes, net 3 3
- --------------------------------------------------------------------------------
Total Current Assets 159 168
- --------------------------------------------------------------------------------
Deferred Debits:
Due from affiliate-pension asset 14 14
Regulatory assets 37 20
Other 7 7
- --------------------------------------------------------------------------------
Total Deferred Debits 58 41
- --------------------------------------------------------------------------------
Total $1,033 $1,024
================================================================================
================================================================================
Capitalization and Liabilities
Capitalization:
Common equity $507 $487
Long-term debt, net 286 286
- --------------------------------------------------------------------------------
Total Capitalization 793 773
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings - 31
Current portion of long-term debt 8 8
Accounts payable 48 44
Accounts payable-affiliated companies 4 7
Customer prepayments and deposits 8 12
Taxes accrued 20 5
Interest accrued 4 6
Distributions/dividends declared 4 5
Other 10 11
- --------------------------------------------------------------------------------
Total Current Liabilities 106 129
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes, net 92 91
Deferred investment tax credits 2 2
Due to affiliate-postretirement benefits 16 16
Regulatory liabilities 12 1
Other 12 12
- --------------------------------------------------------------------------------
Total Deferred Credits 134 122
- --------------------------------------------------------------------------------
Total $1,033 $1,024
================================================================================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
-----------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
--------------------------------------------------------------------------
Operating Revenues $203 $134
Cost of Gas 131 67
-----------------------------------------------------------------------------
Gross Margin 72 67
-----------------------------------------------------------------------------
Operating Expenses:
Operation and maintenance 19 18
Depreciation 9 9
Other taxes 2 2
-----------------------------------------------------------------------------
Total Operating Expenses 30 29
-----------------------------------------------------------------------------
Operating Income 42 38
Other Income, including allowance for equity
funds used during construction 2 2
Interest Charges, net of allowance for borrowed
funds used during construction 5 6
-----------------------------------------------------------------------------
Income Before Income Taxes and Cumulative
Effect of Accounting Change 39 34
Income Taxes 15 13
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting Change 24 21
Cumulative Effect of Accounting Change, net of taxes - (230)
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
Net Income (Loss) $24 $(209)
=============================================================================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -----------------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------- -------------
Cash Flows From Operating Activities:
Net income (loss) $24 $(209)
Adjustments to reconcile net income to net cash
provided from operating activities:
Cumulative effect of accounting change, net of taxes - 230
Depreciation 9 9
Over (under) collection, gas cost adjustment clause (7) (3)
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net (6) 16
(Increase) decrease in inventories 20 20
Increase (decrease) in accounts payable and advances 1 (24)
Increase (decrease) in deferred income taxes, net 1 -
Increase (decrease) in accrued taxes 15 9
Changes in other assets 2 (1)
Changes in other liabilities (7) (1)
- --------------------------------------------------------------------------- -------------
Net Cash Provided From Operating Activities 52 46
- --------------------------------------------------------------------------- -------------
Cash Flows From Investing Activities:
Construction expenditures (10) (9)
Nonutility and other (1) -
- --------------------------------------------------------------------------- -------------
Net Cash Used For Investing Activities (11) (9)
- --------------------------------------------------------------------------- -------------
Cash Flows From Financing Activities:
Repayment of short-term borrowings, net (31) -
Distributions/dividend payments (5) -
- --------------------------------------------------------------------------- -------------
Net Cash Used For Financing Activities (36) -
- --------------------------------------------------------------------------- -------------
Net Increase In Cash and Temporary Investments 5 37
Cash and Temporary Investments, January 1 1 18
- --------------------------------------------------------------------------- -------------
Cash and Temporary Investments, March 31 $6 $55
=========================================================================== =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $0.4 and $0.2) $6 $6
- Income taxes - 4
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------- ----------------
- --------------------------------------------------------------- ----------------
Net Income (Loss) $24 $(209)
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on hedging activities - -
- --------------------------------------------------------------- ----------------
- --------------------------------------------------------------- ----------------
Total Comprehensive Income (Loss) (1) $24 $(209)
=============================================================== ================
(1) Accumulated other comprehensive income (loss) of the Company totaled $(1.2)
million and $(1.3) million as of March 31, 2003 and December 31, 2002,
respectively.
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2003
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in Public Service Company of North
Carolina, Incorporated's (the Company) Annual Report on Form 10-K for the year
ended December 31, 2002. These are interim financial statements, and due to the
seasonality of the Company's business, the amounts reported in the Condensed
Consolidated Statements of Operations are not necessarily indicative of amounts
expected for the year. In the opinion of management, the information furnished
herein reflects all adjustments, all of a normal recurring nature, which are
necessary for a fair statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result, the Company has
recorded as of March 31, 2003 approximately $37 million and $12 million of
regulatory assets and liabilities, respectively, as shown below.
March 31, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------ ----------------
- ------------------------------------------------------------ ----------------
Accumulated deferred income taxes $(1) $(1)
Under-collections - gas cost
adjustment clause 17 11
Deferred environmental remediation costs 9 9
- ------------------------------------------------------------ ----------------
Total $25 $19
============================================================ ================
Accumulated deferred income taxes represent deferred income tax
liabilities applicable to utility operations that have not been reflected in
customer rates for which future recovery is probable, offset by deferred income
tax assets, which will be reflected in customer rates as a result of reduced
revenue requirements due to the amortization of deferred investment tax credits.
Under-collections-gas cost adjustment clause represent amounts
under-collected from customers pursuant to the Company's Rider D
mechanism approved by the North Carolina Utilities Commission (NCUC).
Deferred environmental remediation costs represent costs associated
with the assessment and cleanup of manufactured gas plant (MGP) sites currently
or formerly owned by the Company. Management believes that all MGP cleanup costs
will be recoverable through gas rates. (See Note 5.)
The NCUC has reviewed and approved through specific orders most of the
items shown as regulatory assets. Other items represent costs which are not yet
approved for recovery by the NCUC. In recording these costs as regulatory
assets, management believes the costs will be allowable under existing
rate-making concepts that are embodied in rate orders received by the Company.
However, ultimate recovery is subject to NCUC approval. In the future, as a
result of deregulation or other changes in the regulatory environment, the
Company may no longer meet the criteria for continued application of SFAS 71 and
could be required to write off its regulatory assets and liabilities. Such an
event could have a material adverse effect on the Company's results of
operations in the period the write-off would be recorded, but it is not expected
that cash flows or financial position would be materially affected.
B. New Accounting Standards
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets,"
effective January 1, 2002. In connection with this implementation, the Company
performed a valuation analysis of its acquisition adjustment using an
independent appraisal. The analysis indicated that the carrying amount of the
acquisition adjustment exceeded its fair value by approximately $230 million
effective January 1, 2002. The resulting impairment charge is reflected on the
Condensed Consolidated Statement of Operations as the cumulative effect of an
accounting change. SFAS 142 requires that an impairment evaluation be performed
annually and at the same time each year. The Company performed its annual
evaluation as of January 1, 2003 and no further impairment was indicated.
The Company adopted SFAS 143, "Accounting for Asset Retirement
Obligations," effective January 1, 2003. SFAS 143 applies to legal obligations
associated with the retirement of tangible long-lived assets (ARO) and requires
the Company to recognize, as a liability, the fair value of an ARO in the period
in which it is incurred and to accrete the liability to its present value in
future periods. The Company believes that any ARO related to the Company's
property would be insignificant and, due to the indeterminate life of the
related assets, an ARO could not be reasonably estimated.
The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. The provisions of SFAS 145, among other things,
discontinue treatment of gains or losses from the early extinguishment of debt
as extraordinary items unless such early extinguishment meets the criteria of
Accounting Principles Board Opinion (APB) 30. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.
The Company adopted SFAS 146 "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. This statement requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2003.
2. ACCOUNTING CHANGE
As a result of the January 1, 2002 adoption of SFAS 142, the Company
recorded a $230 million impairment charge related to the acquisition adjustment
recorded in connection with its acquisition by SCANA. The charge is reflected on
the Condensed Consolidated Statements of Operations as the cumulative effect of
an accounting change. See additional information at Note 1B.
3. RATE AND OTHER REGULATORY MATTERS
The Company's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. The Company revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the deferred cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews the Company's gas purchasing
practices annually.
The Company's benchmark cost of gas in effect during the period January
1, 2002 through March 31, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002
$.595 March 2003 $.215 February-June 2002
$.350 July-October 2002
$.410 November-December 2002
On March 31, 2003 the NCUC approved the Company's request to increase
the benchmark cost of gas from $.595 per therm to $.725 per therm effective for
service rendered on and after April 1, 2003.
A state expansion fund, established by the North Carolina General
Assembly and funded by refunds from the Company's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved the
Company's requests for disbursement of up to $28.4 million from the Company's
expansion fund to extend natural gas service to Madison, Jackson and Swain
Counties in western North Carolina. The Company estimates that the cost of this
project will be approximately $31.4 million. The Madison County and Jackson
County portions of the project were completed by the end of 2002. Through March
31, 2003 approximately $17 million had been spent on this project.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of the Company. As specified in the order, the Company agreed to a moratorium on
general rate cases until August 2005. General rate relief can be obtained during
this period to recover costs associated with material adverse governmental
actions and force majeure events.
4. FINANCIAL INSTRUMENTS
SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended, requires the Company to recognize all derivative
instruments as either assets or liabilities in the statement of financial
position and to measure those instruments at fair value. SFAS 133 further
provides that changes in the fair value of derivative instruments are either
recognized in earnings or reported as a component of other comprehensive income,
depending upon the intended use of the derivative and the resulting designation.
The fair value of the derivative instruments is determined by reference to
quoted market prices of listed contracts, published quotations or quotations
from independent parties.
The Company uses interest rate swap agreements to manage interest rate
risk. These swap agreements provide for the Company to pay variable and receive
fixed interest payments and are designated as fair value hedges of certain debt
instruments. The Company may terminate a swap agreement and may replace it with
a new swap also designated as a fair value hedge.
Payments received to terminate a swap are recorded as a basis
adjustment to long-term debt and are amortized as reductions to interest expense
over the term of the underlying debt. The fair value of interest rate swaps is
reflected within other deferred debits on the balance sheet. The fair value of
the debt that is hedged is recorded in long-term debt. Receipts or payments
related to the interest rate swaps are credited or charged to interest expense
as incurred.
At March 31, 2003 the estimated fair value of the Company's swaps
totaled $3.3 million related to combined notional amounts of $40.6 million.
On January 2, 2003 the Company filed a summary of its hedging program
for natural gas purchases with the NCUC for informational purposes. The primary
goal of the program is to reduce price volatility to firm customers. The program
and any related transactions will be addressed in the 2003 annual prudence
review with the NCUC. Transaction fees and any gains or losses are recorded in
deferred accounts for subsequent rate consideration.
5. COMMITMENTS AND CONTINGENCIES
The Company is responsible for environmental cleanup at five sites in
North Carolina on which MGP residuals are present or suspected. The Company's
actual remediation costs for these sites will depend on a number of factors,
such as actual site conditions, third-party claims and recoveries from other
potentially responsible parties. The Company has recorded a liability and
associated regulatory asset of $7.8 million, which reflects the estimated
remaining liability at March 31, 2003. Amounts incurred to date that have not
been recovered through gas rates are approximately $1.2 million. Management
believes that all MGP cleanup costs will be recoverable through gas rates.
6. SEGMENT OF BUSINESS INFORMATION
Gas Distribution is the Company's only reportable segment. Gas
Distribution uses operating income to measure profitability. Intersegment
revenues between Gas Distribution and nonreportable segments were not
significant.
Disclosure of Reportable Segments
(Millions of dollars)
2003 2002
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Three Months Ended External Operating Segment External Operating Segment
March 31, Revenue Income Assets Revenue Income Assets
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Gas Distribution $203 $42 $1,023 $134 $38 $1,202
All Other - n/a 28 - n/a 29
Adjustments/Eliminations - - (18) - - (8)
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Consolidated Total $203 $42 $1,033 $134 $38 $1,223
============================== ============= ================ ============= ============= ============== =============
Item 2. Management's Narrative Analysis of Results of Operations.
---------------------------------------------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Narrative Analysis of Results of Operations appearing in Public Service Company
of North Carolina, Incorporated's (PSNC Energy) Annual Report on Form 10-K for
the year ended December 31, 2002.
Statements included in this narrative analysis (or elsewhere in this
quarterly report) which are not statements of historical fact are intended to
be, and are hereby identified as, "forward-looking statements" for purposes of
the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, (3) changes in the economy, especially in PSNC Energy's service
territory, (4) the impact of competition from other energy suppliers, (5) growth
opportunities, (6) the results of financing efforts, (7) changes in PSNC
Energy's accounting policies, (8) weather conditions, especially in areas served
by PSNC Energy, (9) performance of SCANA Corporation's pension plan assets and
the impact on PSNC Energy's results of operations, (10) inflation, (11) changes
in environmental regulations, and (12) the other risks and uncertainties
described from time to time in PSNC Energy's periodic reports filed with the
United States Securities and Exchange Commission (SEC). PSNC Energy disclaims
any obligation to update any forward-looking statements.
Net Income (Loss) and Distributions/Dividends
Net income (loss) for the three months ended March 31, 2003 and 2002 was
as follows:
- -----------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------- -------------
Net income (loss) $24.1 $(208.8)
Less: Cumulative effect of accounting change - (229.6)
- --------------------------------------------------------------- -------------
- --------------------------------------------------------------- -------------
Income before cumulative effect of accounting change $24.1 $20.8
=============================================================== =============
Income before cumulative effect of accounting change increased
approximately $3.3 million primarily due to increased margin of $5.4 million and
other income of $0.6 million which were partially offset by higher income taxes
of $2.2 million and higher operating expenses of $0.6 million.
In connection with the implementation of SFAS 142, PSNC Energy performed a
valuation analysis of its acquisition adjustment using an independent appraisal.
The analysis indicated that the carrying amount of the acquisition adjustment
exceeded its fair value by $230 million. As a result, PSNC Energy recorded an
impairment charge of $230 million effective January 1, 2002. The charge is
presented on the Condensed Consolidated Statements of Operations as the
Cumulative Effect of an Accounting Change. SFAS 142 requires that an impairment
evaluation be performed annually and at the same time each year. PSNC Energy
performed its annual evaluation as of January 1, 2003 and no further impairment
was indicated.
The nature of PSNC Energy's business is seasonal. The quarters ending
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 authorized the following
distributions/dividends on common stock held by SCANA during 2003:
- --------------------- ---------------- ---------------- -----------------------
Declaration Date Amount Quarter Ended Payment Date
- --------------------- ---------------- ---------------- -----------------------
- --------------------- ---------------- ---------------- -----------------------
February 20, 2003 $4.5 million March 31, 2003 April , 2003
May 1, 2003 $4.5 million June 30, 2003 July 1, 2003
- --------------------- ---------------- ---------------- -----------------------
Gas Distribution
Gas distribution is comprised of the local distribution operations of
PSNC Energy. Changes in the gas distribution sales margins for the three months
ended March 31, 2003 compared to the same period in 2002 were as follows:
-----------------------------------------------------------------------------
Three Months Ended
Millions of dollars 2003 2002 Change
-------------------------------------------------------------------------
---------------------- ------------
Operating revenues $203.2 $133.9 $69.3 51.8%
Less: Cost of gas 131.3 67.4 63.9 94.8%
-------------------------------------------------------
Gross margin $71.9 $66.5 $5.4 8.1%
===================================================================
Gas distribution sales margin for the three months ended March 31, 2003
increased primarily due to weather that was 13% colder than in 2002 and
increased customer growth of approximately 3.5%. Revenues and cost of gas
increased as a result of higher commodity natural gas prices in the first
quarter of 2003.
Operation and Maintenance Expenses
Operation and maintenance expenses increased $0.6 million for the three
months ended March 31, 2003 compared to the same period in 2002 primarily due to
increased bad debt expense.
Income Taxes
Income taxes changed primarily as a result of changes in operating
income.
Capital Expansion Program and Liquidity Matters
PSNC Energy's capital expansion program includes the construction of
lines, systems and facilities and the purchase of related equipment. PSNC
Energy's 2003 construction budget is approximately $46.7 million, compared to
actual construction expenditures for 2002 of $47.8 million. PSNC Energy's ratio
of earnings to fixed charges for the 12 months ended March 31, 2003 was 2.93.
At March 31, 2003 PSNC Energy had no outstanding short-term borrowings
and had unused lines of credit of $125 million.
Item 4. Controls and Procedures
As of March 31, 2003 an evaluation was performed under the supervision
and with the participation of PSNC Energy's management, including the Chief
Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness
of the design and operation of PSNC Energy's disclosure controls and procedures.
Based on that evaluation, PSNC Energy's management, including the CEO and CFO,
concluded that as of March 31, 2003 PSNC Energy's disclosure controls and
procedures were effective. There have been no significant changes in PSNC
Energy's internal controls or in other factors that could significantly affect
internal controls subsequent to March 31, 2003.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The following Legal Proceedings were pending at March 31, 2003. These
proceedings affect the Company and, to the extent indicated, they also affect
SCE&G or PSNC Energy.
Rate and Other Regulatory Matters
In May 2002 the SCPSC issued an order approving SCE&G's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for under-collected actual fuel costs through April 2001,
including short-term purchased power costs necessitated by outages at two of
SCE&G's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002. The Consumer Advocate of
South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the
portion of the SCPSC's order related to the recovery of certain purchased power
costs. The appeal is still pending.
In April 2003 the SCPSC issued an order approving SCE&G's request to
maintain the fuel cost component of rates at 1.678 cents per KWh, effective May
1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices
and recognized the efficiency of SCE&G's electric generating plants; however, it
deferred action on the recovery of certain purchased power costs pending the
appeal to the Circuit Court of the SCPSC's May 2002 order.
On January 2, 2003 PSNC Energy filed a summary of its hedging program
for natural gas purchases with the NCUC for informational purposes. The primary
goal of the program is to reduce price volatility to firm customers. The program
and any related transactions will be addressed in the 2003 annual prudence
review with the NCUC. Transaction fees and any gains or losses are recorded in
deferred accounts for subsequent rate consideration.
Lake Murray Dam Reinforcement
In October 1999 the United States Federal Energy Regulatory Commission
(FERC) mandated that SCE&G reinforce its Lake Murray dam in order to comply with
new federal safety standards and maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001 is expected to cost approximately $275 million and be
completed in 2005. Costs incurred through March 31, 2003 totaled approximately
$83 million.
Environmental
SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. SCE&G
anticipates that the remaining remediation activities will be completed in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
March 31, 2003, SCE&G has spent approximately $18.6 million to remediate the
Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. Two of these sites are currently being
remediated under work plans approved by DHEC. SCE&G is continuing to investigate
the remaining site and is monitoring the nature and extent of residual
contamination. SCE&G anticipates that major remediation activities for these
three sites will be completed before 2006. SCE&G has spent approximately $2.3
million related to these sites, and expects to spend an additional $5.8 million.
In addition, in March 2003 SCE&G signed a consent agreement with DHEC
related to a site formerly owned by SCE&G. The estimated cost for remediation of
this site has not been finalized but is not expected to be material.
PSNC Energy is responsible for environmental cleanup at five sites in
North Carolina on which MGP residuals are present or suspected. PSNC Energy's
actual remediation costs for these sites will depend on a number of factors,
such as actual site conditions, third-party claims and recoveries from other
potentially responsible parties.
PSNC Energy has recorded a liability and associated regulatory asset of $7.8
million, which reflects the estimated remaining liability at March 31, 2003.
Amounts incurred to date that have not been recovered through gas rates are
approximately $1.2 million. Management believes that all MGP cleanup costs
incurred will be recoverable through gas rates.
Pending or Threatened Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets
of SCANA filed suit against SCANA in South Carolina Circuit Court seeking
unspecified damages. The suit alleges the existence of a contract for the sale
of assets to the plaintiff and various causes of action associated with that
contract. The Company is confident in its position and intends to vigorously
defend the lawsuit. The Company does not believe that the resolution of this
issue will have a material impact of its results of operations, cash flows or
financial position.
In 2001 a subsidiary of the Company entered into, in the ordinary
course of business, a 15 year take-and-pay contract with an unaffiliated natural
gas supplier (Supplier) to purchase 190,000 DT of natural gas per day beginning
in the spring of 2004. In December 2002, as a result of the failure of Supplier
and its guarantor to meet contractual obligations related to credit support
provisions, the subsidiary terminated the contract. Attempts to negotiate a new
contract between the parties were not successful, and a hearing under the
binding arbitration provisions of the original contract is scheduled for June
2003. In initial pleadings for the hearing, the Supplier has demanded payment of
at least $134 million in damages from the subsidiary; conversely, the subsidiary
has demanded payment of no less than $154 million in damages from the Supplier.
The Company is confident of the propriety of its actions and will vigorously
pursue its position in such arbitration proceedings. The Company further
believes that the resolution of these claims will not have a material adverse
impact on its results of operations, cash flows or financial condition.
The Company, SCE&G and PSNC Energy are also engaged in various other
claims and litigation incidental to its business operations which management
anticipates will be resolved without material loss to the Company.
Item 2, 3, 4 and 5 are not applicable.
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits
SCANA Corporation, South Carolina Electric & Gas Company and
Public Service Company of North Carolina, Incorporated:
Exhibits filed with this Quarterly Report on Form 10-Q are
listed in the following Exhibit Index. Certain of such exhibits
which have heretofore been filed with the Securities and
Exchange Commission and which are designated by reference to
their exhibit numbers in prior filings are hereby incorporated
herein by reference and made a part hereof.
B. Reports on Form 8-K during the first quarter of 2003 were as
follows:
SCANA Corporation:
Date of report: January 15, 2003
Items reported: Item 5
Date of report: February 18, 2003
Item reported: Item 5
South Carolina Electric & Gas Company:
Date of report: January 15, 2003
Items reported: Item 5
Date of report: January 17, 2003
Items reported: Items 5 & 7
Date of report: February 19, 2003
Item reported: Item 5
Public Service Company of North Carolina, Incorporated: None
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 9, 2003 By: s/James E. Swan, IV
---------------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
CERTIFICATION
I, William B. Timmerman, certify that:
1. I have reviewed this quarterly report on Form 10-Q of SCANA Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: May 9, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, President,
Chief Executive Officer and
Director
CERTIFICATION
I, Kevin B. Marsh, certify that:
1. I have reviewed this quarterly report on Form 10-Q of SCANA
Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 9, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial Officer
CERTIFICATION
I, William B. Timmerman, certify that:
1. I have reviewed this quarterly report on Form 10-Q of South Carolina
Electric & Gas Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: May 9, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive Officer
and Director
CERTIFICATION
I, Kevin B. Marsh, certify that:
1. I have reviewed this quarterly report on Form 10-Q of South Carolina
Electric & Gas Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: May 9, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial Officer
CERTIFICATION
I, William B. Timmerman, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Public Service
Company of North Carolina, Incorporated;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: May 9, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive Officer
and Director
CERTIFICATION
I, Kevin B. Marsh, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Public Service
Company of North Carolina, Incorporated;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: May 9, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial
Officer
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
2.01 X X Agreement and Plan of Merger, dated as of February
16, 1999 as amended and restated as of May 10, 1999,
by and among Public Service Company of North
Carolina, Incorporated, SCANA Corporation, New Sub I,
Inc. and New Sub II, Inc. (Filed as Exhibit 2.1 to
Registration Statement No. 333-78227 on Form S-4)
3.01 X Restated Articles of Incorporation of SCANA as
adopted on April 26, 1989 (Filed as Exhibit 3-A to
Registration Statement No. 33-49145)
3.02 X Articles of Amendment of SCANA, dated April 27, 1995
(Filed as Exhibit 4-B to Registration Statement No.
33-62421)
3.03 X Restated Articles of Incorporation of SCE&G, as
adopted on May 3, 2002 (Filed as Exhibit 3.01 to
Registration Statement No. 333-65460)
3.04 X Articles of Amendment of SCE&G dated as of the dates
indicated below and filed as exhibits to the
Registration Statements as set forth below
March 13, 2002 Exhibit 3.06 to Registration No. 333-101449
May 9, 2002 Exhibit 3.07 to Registration No. 333-101449
May 22, 2002 Exhibit 3.02 to Registration No. 333-65460
June 4, 2002 Exhibit 3.08 to Registration No. 333-101449
June 14, 2002 Exhibit 3.04 to Registration No. 333-65460
August 12, 2002 Exhibit 3.09 to Registration No. 333-101449
August 30, 2002 Exhibit 3.05 to Registration No. 333-101449
3.05 X Articles of Amendment of SCE&G, dated March 13, 2003
(Filed herewith)
3.06 X Articles of Correction of SCE&G dated June 1, 2002
(Filed as Exhibit 3.03 to Registration Statement No.
333-65460)
3.07 X Articles of Incorporation of PSNC Energy (formerly
New Sub II, Inc.) dated February 12, 1999 (Filed as
Exhibit 3.01 to Registration Statement No.
333-45206)
3.08 X Articles of Amendment of PSNC Energy (formerly New
Sub II, Inc.) as adopted on February 10, 2000 (Filed
as Exhibit 3.02 to Registration Statement No.
333-45206)
3.09 X Articles of Correction of PSNC Energy dated February
11, 2000 (Filed as Exhibit 3.03 to Registration
Statement No. 333-45206)
3.10 X By-Laws of SCANA as revised and amended on December
13, 2000 (Filed as Exhibit 3.01 to Registration
Statement No. 333-68266)
3.11 X By-Laws of SCE&G as amended and adopted on February
22, 2001 (Filed as Exhibit
3.05 to Registration Statement No. 333-65460)
3.12 X By-Laws of PSNC Energy (formerly New Sub II, Inc.)
as revised and amended on February 22, 2001 (Filed
as Exhibit 3.01 to Registration Statement No.
333-68516)
Exhibit Appable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
4.01 X Articles of Exchange of South Carolina Electric
and Gas Company and SCANA Corporation (Filed as
Exhibit 4-A to Post-Effective Amendment
No. 1 to Registration Statement No. 2-90438)
4.02 X Indenture dated as of November 1, 1989 between
SCANA Corporation and The Bank of New York, as
Trustee (Filed as Exhibit 4-A to Registration
Statement No.33-32107)
4.03 X X Indenture dated as of January 1, 1945, between
the South Carolina Power Company and Central
Hanover Bank and Trust Company, as Trustee, as
supplemented by three Supplemental Indentures
dated respectively as of May 1, 1946, May 1, 1947
and July 1, 1949 (Filed as Exhibit 2-B to
Registration Statement No. 2-26459)
4.04 X X Fourth Supplemental Indenture dated as of April
1, 1950, to Indenture referred to in Exhibit
4.03, pursuant to which SCE&G assumed said
Indenture (Filed as Exhibit 2-C to Registration
Statement No. 2-26459)
4.05 X X Fifth through Fifty-third Supplemental Indentures
to Indenture referred to in Exhibit 4.03 dated as
of the dates indicated below and filed as
exhibits to the Registration Statements whose
file numbers are set forth below
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-O to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 2-B to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
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
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
June 1, 1986 Exhibit 4-D to Registration No. 33-49421
September 1, 1987 Exhibit 4-D to Registration No. 33-49421
January 1, 1989 Exhibit 4-D to Registration No. 33-49421
January 1, 1991 Exhibit 4-D to Registration No. 33-49421
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
May 1, 1999 Exhibit 4.04 to Registration No. 333-86387
4.06 X X Indenture dated as of April 1, 1993 from South Carolina
Electric & Gas Company to NationsBank of Georgia, National
Association (Filed as Exhibit 4-F to Registration
Statement No. 33-49421)
4.07 X X First Supplemental Indenture to Indenture referred to in
Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit
4-G to Registration Statement No. 33-49421)
4.08 X X Second Supplemental Indenture to Indenture referred to in
Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit
4-G to Registration Statement No. 33-57955)
4.09 X X Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.03
to Registration Statement No. 333-49960)
4.10 X X Certificate of Trust of SCE&G Trust I (Filed as Exhibit
4.04 to Registration Statement No. 333-49960)
4.11 X X Junior Subordinated Indenture for SCE&G Trust I (Filed as
Exhibit 4.05 to Registration Statement No. 333-49960)
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as Exhibit
4.06 to Registration Statement No. 333-49960)
4.13 X X Amended and Restated Trust Agreement for SCE&G Trust I
(Filed as Exhibit 4.07 to Registration Statement No.
333-49960)
4.14 X X Indenture dated as of January 1, 1996 between PSNC Energy
and First Union National Bank of North Carolina, as
Trustee (Filed as Exhibit 4.08 to Registration Statement
No. 333-45206)
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
4.15 X X First through Fourth Supplemental Indentures
referred to Exhibit 4.14 dated as of the dates
indicated below and filed as exhibits to the
Registration Statements whose file numbers are set
forth below
January 1, 1996 Exhibit 4.09 to Registration No. 333-45206
December 15, 1996 Exhibit 4.10 to Registration No. 333-45206
February 10, 2000 Exhibit 4.11 to Registration No. 333-45206
February 12, 2001 Exhibit 4.05 to Registration No. 333-68516
4.16 X PSNC Energy $150 million medium-term note issued
February 16, 2002 (Filed as Exhibit 4.06 to
Registration Statement No. 333-68516)
*10.01 X SCANA Executive Deferred
Compensation Plan as amended July
1, 2001 (Filed as Exhibit 10.01
to Form 10-Q for the quarter
ended September 30, 2001)
*10.02 X SCANA Supplemental Executive
Retirement Plan as amended July
1, 2001 (Filed as Exhibit 10.02
to Form 10-Q for the quarter
ended September 30, 2001)
*10.03 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)
*10.04 X SCANA Supplementary Key
Executive Severance Benefits Plan
as amended July 1, 2001 (Filed as
Exhibit 10.03a to Form 10-Q for
the quarter ended September 30,
2001)
*10.05 X SCANA Performance Share Plan as
amended and restated effective January 1, 1998
(Filed as Exhibit 10 (e) to Registration
Statement No. 333-86803)
*10.06 X SCANA Long-Term Equity Compensation Plan dated
January 2000 filed as Exhibit 4.04
to Registration Statement No. 333-37398)
*10.07 X Description of SCANA Whole Life
Option (Filed as Exhibit 10-F to
Form 10-K for the year ended
December 31, 1991, under cover of
Form SE, File No. 1-8809)
*10.08 X Description of SCANA
Corporation Executive Annual
Incentive Plan (Filed as Exhibit
10-G to Form 10-K for the year
ended December 31, 1991, under
cover of Form SE, File No.
1-8809)
*10.09 X SCANA Corporation Director
Compensation and Deferral Plan
effective January 1, 2001 (Filed
as Exhibit 10.05 to Registration
Statement No. 333-49960)
10.10 X Operating Agreement of Pine Needle LNG Company,
LLC dated August 8, 1995 (Filed as Exhibit
10.01 to Registration Statement No. 333-45206)
10.11 X Amendment to Operating Agreement of Pine Needle
LNG Company, LLC dated October 1, 1995 (Filed as
Exhibit 10.02 to Registration Statement No.
333-45206)
Exhibi Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
10.12 X Amended Operating Agreement of Cardinal Extension
Company, LLC dated December 19, 1996 (Filed as
Exhibit 10.03 to Registration Statement No.
333-45206)
10.13 X Amended Construction, Operation and Maintenance
Agreement by and between Cardinal
Operating Company and Cardinal Extension Company,
LLC dated December 19, 1996(Filed as Exhibit 10.04
to Registration Statement No. 333-45206)
10.14 X Form of Severance Agreement between PSNC Energy
and its Executive Officers (Filed
as Exhibit 10.05 to Registration Statement No.
333-45206)
10.15 X Service Agreement between PSNC Energy and SCANA
Services, Inc., effective April 1, 2000 (Filed as
Exhibit 10.06 to Registration Statement No.
333-45206)
10.16 X Service Agreement between SCE&G and SCANA
Services, Inc., effective April 1, 2002
(Filed as Exhibit 10.01 to Registration Statement
No. 333-101449)
99.1 X Certification of Principal Executive Officer
(Filed herewith)
99.2 X Certification of Principal Financial Officer
(Filed herewith)
99.3 X Certification of Principal Executive Officer
(Filed herewith)
99.4 X Certification of Principal Financial Officer
(Filed herewith)
99.5 X Certification of Principal Executive Officer
(Filed herewith)
99.6 X Certification of Principal Financial Officer
(Filed herewith)
* Management Contract or Compensatory Plan or Arrangement
Exhibit 99.1
SCANA CORPORATION
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of SCANA Corporation (the
"Company") on Form 10-Q for the quarter ended March 31, 2003 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I certify
pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the
Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result of
operations of the Company.
Dated: May 9, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, President, Chief Executive Officer and Director
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.2
SCANA CORPORATION
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of SCANA Corporation (the
"Company") on Form 10-Q for the quarter ended March 31, 2003 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I certify
pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the
Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result
of operations of the Company.
Dated: May 9, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.3
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of South Carolina Electric and
Gas Company (the "Company") on Form 10-Q for the quarter ended March 31, 2003 as
filed with the Securities and Exchange Commission on the date hereof (the
"Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss.
906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result
of operations of the Company.
Dated: May 9, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive Officer and Director
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.4
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of South Carolina Electric and
Gas Company (the "Company") on Form 10-Q for the quarter ended March 31, 2003 as
filed with the Securities and Exchange Commission on the date hereof (the
"Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss.
906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result
of operations of the Company.
Dated: May 9, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.5
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Public Service Company of
North Carolina, Incorporated (the "Company") on Form 10-Q for the quarter ended
March 31, 2003 as filed with the Securities and Exchange Commission on the date
hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted
pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result
of operations of the Company.
Dated: May 9, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive Officer and Director
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.6
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Public Service Company of
North Carolina, Incorporated (the "Company") on Form 10-Q for the quarter ended
March 31, 2003 as filed with the Securities and Exchange Commission on the date
hereof (the "Report"), I certify pursuant to 18 U.S.C. ss. 1350, as adopted
pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result
of operations of the Company.
Dated: May 9, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.