UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
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. Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the last practicable date.
Description of Shares Outstanding
Registrant Common Stock at October 31,
- ---------- ------------ ---------------
2002
SCANA Corporation Without Par Value 110,738,310
South Carolina Electric
& Gas Company Par Value $4.50 Per Share 40,296,147(a)
Public Service Company of
North Carolina, Incorporated Without Par Value 1,000(a)
(a)Held beneficially and of record by SCANA Corporation.
This combined Form 10-Q is separately filed by SCANA Corporation, South
Carolina Electric & Gas Company and Public Service Company of North Carolina,
Incorporated. Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no representation as
to information relating to the other companies.
Public Service Company of North Carolina, Incorporated meets the
conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and
therefore is filing this form with the reduced disclosure format allowed under
General Instruction H(2).
===============================================================================
2
INDEX
Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section.................................... 3
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of September
30, 2002 and December 31, 2001 ........................ 4
Condensed Consolidated Statements of Income for
the Periods Ended September 30, 2002 and 2001.......... 6
Condensed Consolidated Statements of Cash Flows
for the Periods Ended September 30, 2002 and 2001...... 7
Condensed Consolidated Statements of Comprehensive
Income (Loss) for the Periods
Ended September 30, 2002 and 2001...................... 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.. 29
Item 4. Controls and Procedures..................................... 31
South Carolina Electric & Gas Company Financial Section............... 32
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of September
30, 2002 and December 31, 2001 ........................ 33
Condensed Consolidated Statements of Income for
the Periods Ended September 30, 2002 and 2001.......... 35
Condensed Consolidated Statements of Cash Flows
for the Periods Ended September 30, 2002 and 2001...... 36
Notes to Condensed Consolidated Financial Statements.... 37
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 42
Item 3. Quantitative and Qualitative Disclosures About Market Risk... 48
Item 4. Controls and Procedures...................................... 48
Public Service Company of North Carolina, Incorporated Financial
Section...................................................... 49
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of September
30, 2002 and December 31, 2001 ....................... 50
Condensed Consolidated Statements of Operations for
the Periods Ended September 30, 2002 and 2001......... 51
Condensed Consolidated Statements of Cash Flows for
the Periods Ended September 30, 2002 and 2001.......... 52
Notes to Condensed Consolidated Financial Statements......... 53
Item 2. Management's Narrative Analysis of Results of Operations..... 57
Item 4. Control and Procedures....................................... 59
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................ 60
Item 6. Exhibits and Reports on Form 8-K............................. 66
Signatures............................................................ 67
Certifications Required by Rule 13a-14 ............................... 70
Exhibit Index......................................................... 76
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ---------------------------------------------------------------------------- ------------------
ember 30, December 31,
Millions of dollars 2002 2001
- ---------------------------------------------------------------------------- ------------------
Assets
Utility Plant:
Electric 5,182 $4,855
Gas 1,559 1,536
Other 191 187
- ---------------------------------------------------------------------------- ------------------
Total 6,932 6,578
Accumulated depreciation and amortization (2,476) (2,364)
- ---------------------------------------------------------------------------- ------------------
Total 4,456 4,214
Construction work in progress 584 544
Nuclear fuel, net of accumulated amortization 44 45
Acquisition adjustments, net of accumulated amortization 460 460
- ---------------------------------------------------------------------------- ------------------
Utility Plant, Net 5,544 5,263
- ---------------------------------------------------------------------------- ------------------
Nonutility Property, Net of Accumulated Depreciation 91 93
Investments 192 191
- ---------------------------------------------------------------------------- ------------------
- ---------------------------------------------------------------------------- ------------------
Nonutility Property and Investments, Net 283 284
- ---------------------------------------------------------------------------- ------------------
- ---------------------------------------------------------------------------- ------------------
Current Assets:
Cash and temporary investments 194 212
Receivables (net of allowance for uncollectible accounts of
$26 and $37) 343 424
Inventories (at average cost):
Fuel 174 164
Materials and supplies 61 59
Emission allowances 11 13
Prepayments 22 21
Investments 151 664
- ---------------------------------------------------------------------------- ------------------
Total Current Assets 956 1,557
- ---------------------------------------------------------------------------- ------------------
Deferred Debits:
Environmental 29 34
Nuclear plant decommissioning fund 84 79
Pension asset, net 259 239
Other regulatory assets 232 210
Other 192 156
- ---------------------------------------------------------------------------- ------------------
Total Deferred Debits 796 718
- ---------------------------------------------------------------------------- ------------------
Total $7,579 $7,822
============================================================================ ==================
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------- -----------------
September 30, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------- -----------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,183 $2,194
Preferred stock (Not subject to purchase or sinking funds) 106 106
- --------------------------------------------------------------------------------- -----------------
Total Stockholders' Investment 2,289 2,300
Preferred Stock, net (Subject to purchase or sinking funds) 9 10
SCE&G-Obligated Mandatorily Redeemable Preferred
Securities of SCE&G's Subsidiary Trust, SCE&G Trust
I, holding solely $50 million principal amount
of the 7.55%Junior Subordinated Debentures of SCE&G,
due 2027 50 50
Long-Term Debt, net 2,937 2,646
- --------------------------------------------------------------------------------- -----------------
Total Capitalization 5,285 5,006
- --------------------------------------------------------------------------------- -----------------
Current Liabilities:
Short-term borrowings 233 165
Current portion of long-term debt 299 739
Accounts payable 213 275
Customer deposits 46 41
Taxes accrued 64 82
Interest accrued 54 45
Dividends declared 36 34
Deferred income taxes, net 23 154
Other 28 26
- --------------------------------------------------------------------------------- -----------------
Total Current Liabilities 996 1,561
- --------------------------------------------------------------------------------- -----------------
Deferred Credits:
Deferred income taxes, net 739 720
Deferred investment tax credits 115 118
Reserve for nuclear plant decommissioning 84 79
Postretirement benefits 129 122
Other regulatory liabilities 110 100
Other 121 116
- --------------------------------------------------------------------------------- -----------------
Total Deferred Credits 1,298 1,255
- --------------------------------------------------------------------------------- -----------------
Total $7,579 $7,822
================================================================================= =================
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- ------------------------------------------------------------------------------------- -------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars, except per share amounts 2002 2001 2002 2001
- ----------------------------------------------------------------------- ------------- ----------- -------------
Operating Revenues:
Electric $424 $416 $1,075 $1,097
Gas - regulated 136 133 587 775
Gas - nonregulated 134 161 503 897
- ----------------------------------------------------------------------- ------------- ----------- -------------
Total Operating Revenues 694 710 2,165 2,769
- ----------------------------------------------------------------------- ------------- ----------- -------------
Operating Expenses:
Fuel used in electric generation 105 87 271 222
Purchased power 7 43 29 131
Gas purchased for resale 215 235 828 1,383
Other operation and maintenance 126 117 383 367
Depreciation and amortization 55 56 163 168
Other taxes 32 29 95 88
- ----------------------------------------------------------------------- ------------- ----------- -------------
Total Operating Expenses 540 567 1,769 2,359
- ----------------------------------------------------------------------- ------------- ----------- -------------
Operating Income 154 143 396 410
- ----------------------------------------------------------------------- ------------- ----------- -------------
Other Income:
Other income, including allowance for equity funds
used during construction of $6, $4, $18 and $8 17 12 54 43
Gain on sale of investments and assets - 1 31 556
Impairment of investments - - (255)
-
- ----------------------------------------------------------------------- ------------- ----------- -------------
Total Other Income 17 13 (170) 599
- ----------------------------------------------------------------------- ------------- ----------- -------------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 171 156 226 1,009
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction of $3, $3, $10 and $8 49 52 151 173
Preferred Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 1 3 3
- ----------------------------------------------------------------------- ------------- ----------- -------------
Income Before Income Taxes and Preferred Stock Dividends 121 103 72 833
Income Taxes 41 38 20 300
- ----------------------------------------------------------------------- ------------- ----------- -------------
Income Before Preferred Stock Dividends 80 65 52 533
Cash Dividends on Preferred Stock of Subsidiary
(At stated rates) 2 2 6 6
- ------------------------------------------------------------------------ ------------- ----------- -------------
- ------------------------------------------------------------------------ ------------- ----------- -------------
Net Income $78 $63 $46 $527
======================================================================== ============= =========== =============
======================================================================== ============= =========== =============
Basic and Diluted Earnings Per Share of Common Stock $.74 $.61 $.44 $5.03
Weighted Average Shares Outstanding (millions) 104.7 104.7 104.7 104.7
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2002 2001
- ---------------------------------------------------------------------------------------- ---------------
Cash Flows From Operating Activities:
Net income $46 $527
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 172 174
Amortization of nuclear fuel 14 11
Gain on sale of investments and assets (31) (556)
Hedging activities 45 (95)
Impairment on investments 255 -
Allowance for funds used during construction (28) (16)
Over (under) collection, fuel adjustment clauses (39) 17
Changes in certain assets and liabilities:
(Increase) decrease in receivables 82 299
(Increase) decrease in inventories (10) (53)
(Increase) decrease in prepayments (1)
(16)
(Increase) decrease in pension asset (20) (32)
(Increase) decrease in other regulatory assets 3 (2)
Increase (decrease) in deferred income taxes, net (138) 210
Increase (decrease) in regulatory liabilities 32 18
Increase (decrease) in postretirement benefits 7 6
Increase (decrease) in accounts payable (62) (235)
Increase (decrease) in taxes accrued (18) 22
Increase (decrease) in interest accrued 9 18
Changes in other assets (1) -
Changes in other liabilities 33 (27)
- ---------------------------------------------------------------------------------------- ---------------
Net Cash Provided From Operating Activities 350 270
- ---------------------------------------------------------------------------------------- ---------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (424) (311)
Proceeds from sale of investments and assets 335 28
Increase in nonutility property (12) (35)
Investments in affiliates (25) (43)
- ---------------------------------------------------------------------------------------- ---------------
- ---------------------------------------------------------------------------------------- ---------------
Net Cash Used For Investing Activities (126) (361)
- ---------------------------------------------------------------------------------------- ---------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149
Issuance of notes and loans 497 654
Repayments:
First and Refunding Mortgage Bonds (104) -
Notes and loans (907) (308)
Retirement of preferred stock (1) -
Dividends and distributions:
Common stock (100) (92)
Preferred stock (6) (6)
Short-term borrowings, net 84 (323)
- ---------------------------------------------------------------------------------------- ---------------
Net Cash Provided From (Used For) Financing Activities (242) 74
- ---------------------------------------------------------------------------------------- ---------------
Net Decrease In Cash and Temporary Investments (18) (17)
Cash and Temporary Investments, January 1 212 159
- ---------------------------------------------------------------------------------------- ---------------
Cash and Temporary Investments, September 30 $194 $142
======================================================================================== ===============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $10 and $8) $142 $162
- Income taxes 131 41
Noncash Investing and Financing Activities:
Unrealized gain (loss) on securities available for sale, net of tax 17 (294)
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- ----------------------------------------------------------------------- ----------------------- -----------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars 2002 2001 2002 2001
- ----------------------------------------------------------------------- ----------- ----------- ----------- -----------
- ----------------------------------------------------------------------- ----------- ----------- ----------- -----------
Net Income $78 $63 $46 $527
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on securities available for sale (12) (195) 17 (294)
Unrealized gains (losses) on hedging activities 1 (10) 28 (63)
Cumulative effect of change in accounting for hedging activities - - - 23
- ----------------------------------------------------------------------- ----------- ----------- ----------- -----------
Total Comprehensive Income (Loss) (1) $67 $(142) $91 $193
======================================================================= =========== =========== =========== ===========
(1) Accumulated other comprehensive loss of the Company totaled $(68) million
and $(113) million as of September 30, 2002 and December 31, 2001,
respectively.
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2002
(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, 2001. 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 September 30, 2002 approximately $261 million and $110 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $140 million and
$101 million, respectively. The electric and gas regulatory assets of
approximately $51 million and $70 million, respectively (excluding deferred
income tax assets), are recoverable through rates. The Public Service Commission
of South Carolina (SCPSC) and the North Carolina Utilities Commission (NCUC)
have reviewed and approved most of the items shown as regulatory assets through
specific orders. Other items represent costs which are not yet approved for
recovery by the SCPSC or the NCUC, but are the subject of current or future
filings. In recording these costs as regulatory assets, management believes the
costs will be allowable under existing rate-making concepts that are embodied in
current 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 141, "Business Combinations," and SFAS 142,
"Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141
requires all acquisitions to be accounted for utilizing the purchase method. The
Company considers the amounts categorized by the Federal Energy Regulatory
Commission (FERC) as "acquisition adjustments" to be goodwill as defined in SFAS
142 and ceased amortization of such amounts upon the adoption of SFAS 142. This
amortization is related to acquisition adjustments of approximately $466 million
carried on the books of Public Service Company of North Carolina, Incorporated
(PSNC) and approximately $40 million carried on the books of South Carolina
Pipeline Corporation (SCPC). The Company has no other intangible assets subject
to amortization as provided in SFAS 142.
If the Company had ceased amortization during all periods presented in
the condensed consolidated statements of income, net income and basic and
diluted earnings per share would have been as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
(Millions of dollars, except per share amounts) 2002 2001 2002 2001
---- ---- ---- ----
Net Income as Reported $78 $63 $46 $527
Amortization of Acquisition Adjustment - 4 - 11
---- - ---- -- ---- - ---- --
Net Income as Adjusted $78 $67 $46 $538
=== === === ====
Basic and Diluted Earnings Per Share As Reported $.74 $.61 $.44 $5.03
Amortization of Acquisition Adjustment - .03 - .10
---- - -- --- ------ - ---- ---
Basic and Diluted Earnings Per Share As Adjusted $.74 $.64 $.44 $5.13
==== ==== ==== =====
SFAS 142 provides a six-month transitional period from the effective
date of adoption for the Company to perform an assessment of whether there is an
indication that goodwill is impaired. The Company's initial analysis indicated
that a write-down of the acquisition adjustment associated with PSNC ranging
from $200 million to $250 million will be required. The final valuation analysis
will be completed by December 31, 2002, and any write-down resulting from the
analysis will be recorded as the cumulative effect of a change in accounting
principle.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing liabilities related to the future
obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective
January 1, 2003. The impact SFAS 143 may have on the Company's financial
position has not been determined but could be material, particularly in regards
to the V. C. Summer Nuclear Station (Summer Station). The Company does not
expect that any other ARO liability would be material or subject to accrual due
to uncertainty of timing of cash flows. Because any ARO anticipated to be
recorded would relate to regulated operations, it is not expected that the
initial adoption of the statement will have any impact on results of operations
or cash flows.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," became effective January 1, 2002. This statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The
provisions of SFAS 145, among other things, discontinue treating 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. The Company will adopt SFAS 145 effective January 1, 2003, and does not
expect that initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. 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.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
C. Stock Option Plan
The Company sponsors the SCANA Corporation Long-Term Equity
Compensation Plan (the Plan), under which certain employees and non-employee
directors may receive nonqualified stock options and other forms of equity
compensation. The Company accounts for this equity-based compensation under 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." At September 30, 2002, options issued
and outstanding under the Plan totaled approximately 1.8 million.
D. Earnings Per Share
Earnings per share amounts have been computed in accordance with SFAS
128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed
by dividing net income by the weighted average number of common shares
outstanding for the period. Diluted earnings per share are computed as net
income divided by the weighted average number of shares of common stock
outstanding during the period after giving effect to securities considered to be
dilutive potential common stock. The Company uses the treasury stock method in
determining total dilutive potential common stock.
E. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company (SCE&G)
Electric
SCE&G filed an application with the SCPSC requesting
a $104.7 million increase in retail electric revenues. The electric rate request
is largely associated with the power generation projects recently completed at
Urquhart Station and the Jasper County Generating Station currently under
construction. It also includes costs for equipment required for environmental
and air quality improvements. Hearings on this request are to be held in late
November 2002, with an order expected in February 2003.
In April 2002 the SCPSC approved SCE&G's request to increase the fuel
component of rates charged to electric customers from 1.579 cents per
kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2002 through April 2003. The increase
also provides recovery for under-collected actual fuel costs through April 2002,
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.
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,
2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-September 2002
On October 22, 2002, as part of the annual review of gas costs, the
SCPSC approved SCE&G's request to increase the cost of gas component from $.596
per therm to $.728 per therm effective with the first billing cycle in November
2002.
In 1994 the SCPSC issued an order approving SCE&G's request to recover,
through a billing surcharge to its gas customers, the costs of environmental
cleanup at the sites of former manufactured gas plants (MGPs). The billing
surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for SCE&G's gas operations that had previously
been deferred. In October 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 of the balance remaining at September 30, 2002
($19.7 million) prior to the end of 2005.
Public Service Company of North Carolina, Incorporated (PSNC)
PSNC'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 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's gas purchasing practices annually.
PSNC's benchmark cost of gas in effect during the period January 1,
2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2002
$.750 February-March 2001 $.215 February-June 2002
$.650 April-August 2001 $.350 July-September 2002
$.500 September-October 2001
$.350 November-December 2001
On October 28, 2002 the NCUC approved PSNC's request to increase the
benchmark cost of gas from $.350 per therm to $.410 per therm effective for
service rendered on and after November 1, 2002.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund to
extend natural gas service to Madison, Jackson and Swain Counties in western
North Carolina. PSNC estimates that the cost of this project will be
approximately $31.4 million. The Madison County portion of the project was
completed in 2001. The Jackson County portion of the project should be complete
by the end of 2002. At September 30, 2002 approximately $14.5 million had been
spent on this project.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately
$1 million in each of August 2000 and August 2001, and agreed to a moratorium on
general rate cases until August 2005. General rate relief can be obtained during
this period to recover costs associated with material adverse governmental
actions and force majeure events.
South Carolina Pipeline Corporation (SCPC)
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In an order dated August 15, 2002
the SCPSC found that for the period January 2001 through March 2002 SCPC's gas
purchasing policies and practices were prudent and the gas cost recovery
provisions of its gas tariff were properly adhered to.
3. LONG-TERM DEBT
On January 31, 2002 SCANA issued $250 million of medium-term notes
maturing February 1, 2012 and bearing a fixed interest rate of 6.25 percent.
Also on January 31, 2002 SCANA issued $150 million of two-year floating rate
notes maturing February 1, 2004. The interest rate on the floating rate notes is
reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from
these issuances were used to refinance $400 million of two-year floating rate
notes that matured February 8, 2002, which had been issued to finance SCANA's
acquisition of PSNC.
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem on
March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds, 8 7/8
percent Series due August 15, 2021.
On July 15, 2002 SCANA retired at maturity $300 million of floating rate
medium-term notes. The notes were bearing interest at a rate of 4.063 percent at
maturity.
On August 15, 2002 SCANA issued $100 million one-year floating rate
medium term notes maturing August 15, 2003. The interest rate on the notes is
reset quarterly based on three-month LIBOR plus 87.5 basis points. The proceeds
were used for general corporate purposes.
4. RETAINED EARNINGS
The Company's Restated Articles of Incorporation do not limit the
dividends that may be payable on its common stock. However, the Restated
Articles of Incorporation of SCE&G contain provisions that, under certain
circumstances, could limit the payment of cash dividends on its common stock. In
addition, with respect to hydroelectric projects, the Federal Power Act requires
the appropriation of a portion of certain earnings therefrom. At September 30,
2002 approximately $40 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.
5. FINANCIAL INSTRUMENTS
Investments
SCANA and certain of its subsidiaries hold investments in marketable
securities, some of which are subject to SFAS 115 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, 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 are categorized as "held to maturity" and are carried at
amortized cost. When indicated, and in accordance with its stated accounting
policy, the Company performs periodic assessments of whether any decline in the
value of these securities to amounts below the Company's cost basis is other
than temporary. When other than temporary declines occur, write-downs are
recorded through operations, and new (lower) cost bases are established.
At September 30, 2002 SCANA and SCANA Communications Holdings, Inc.
(SCH), a wholly owned, indirect subsidiary of SCANA, held marketable equity and
debt securities in the following companies in the amounts noted in the table
below.
As of September 30, 2002
Unrealized
Investee Held Securities (a) Basis Market Gain (Loss)
By (b)
- ------------------------- --------------------------------------------------------------- -------- ------------- ---------------
(Millions of dollars)
DTAG SCH 18.3 million ordinary shares $258.0 $151.4 $(106.6)
ITC SCH 3.1 million shares common stock 5.8 (c) n/a
SCH 645,153 shares series A convertible preferred stock 7.2 (c) n/a
SCH 133,664 shares series B convertible preferred stock 4.0 (c) n/a
ITC^DeltaCom SCH 5.1 million shares common stock - - -
SCH 1.5 million shares series A convertible preferred stock - - -
SCANA 5,318 shares series B-1 preferred stock convertible into
932,894
shares of common stock - - -
SCANA 6,973 shares series B-2 preferred stock convertible into
2,723,828
shares of common stock - - -
SCANA Warrants to purchase approximately 1.0 million shares of
common stock - - -
Knology SCH 7.2 million shares series A preferred stock, convertible into
7.5
million shares of common stock 14.0 (c) n/a
SCH Warrants to purchase 159,180 shares series A convertible
preferred stock, convertible into 165,086 shares of common - (c) n/a
stock
SCH 8.3 million shares series C preferred stock, convertible into
8.3
million shares of common stock 15.6 (c) n/a
Knology
Broadband SCH $118,071,000 face amount, 11.875% Senior Discount notes due 82.1 (d) n/a
2007
(a) Convertible preferred stock is convertible into common stock at any time.
(b) Amounts are included in accumulated other comprehensive income (loss), net
of taxes. (c) Market value not readily determinable.
(d) Market value not readily determinable, classified as held to maturity.
Deutsche Telekom AG (DTAG) is an international telecommunications
carrier. On March 1, 2002 the Company determined that the decline in value of
its investment in DTAG to below its cost basis of $20.30 per share was other
than temporary, and recorded an impairment loss of approximately $160 million
(after tax). In March 2002 SCH sold 21 million ordinary shares of DTAG at a
weighted average price of $14.82 per share through a series of market
transactions. The sales resulted in net after tax proceeds of approximately $250
million.
ITC Holding Company (ITC) holds ownership interests in several
Southeastern communications companies. ITC^DeltaCom, Inc. (ITCD) is a regional
provider of telecommunications services. Knology, Inc. (Knology) is a broadband
service provider of cable television, telephone and internet services. Knology
Broadband, Inc. (Knology Broadband) is a wholly-owned subsidiary of Knology.
In June 2002 ITCD announced plans for a reorganization and entered into
Chapter 11 bankruptcy. As a result the Company and SCH wrote off their
investments in ITCD in the second quarter and recorded an aggregate impairment
charge of approximately $7.0 million (after tax). The bankruptcy court accepted
the reorganization plan, and ITCD emerged from bankruptcy on October 29, 2002.
In connection with ITCD's emergence from bankruptcy, SCH provided $15 million in
preferred equity financing.
In July 2002 Knology negotiated a potential exchange of its Knology
Broadband discount notes for a combination of new notes and new preferred stock.
In contemplation of the anticipated exchange, the Company recorded an impairment
loss of approximately $0.3 million (after-tax) in the second quarter. Because
the exchange offer did not result in the requisite minimum tender of notes, in
the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which
reflected the same terms of exchange. The bankruptcy court accepted the
reorganization plan, and in connection with Knology's emergence from bankruptcy,
SCH purchased an additional 6.5 million shares of series C preferred stock for
approximately $19.5 million.
Derivatives
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires
the Company to recognize all derivative instruments as either assets or
liabilities in the statement of financial position and to measure those
instruments at fair value. SFAS 133 further provides that changes in the fair
value of derivative instruments are either recognized in earnings or reported as
a component of other comprehensive income (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.
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 the authority for setting market risk
limits to a Risk Management Committee, which is comprised of certain officers
and senior officers of the Company. The Risk Management Committee provides
assurance to the Board of Directors with regard to compliance with risk
management policies and brings to the Board's attention any areas of concern.
Written policies define the physical and financial transactions that are
approved, as well as the authorization requirements and limits for those
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. 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.
As a result of adopting SFAS 133, the Company recorded a credit to other
comprehensive income (loss) of approximately $23.0 million, net of tax, as the
effect of the change in accounting principle (transition adjustment) on January
1, 2001. This amount represents the reclassification of unrealized gains that
were deferred and reported as liabilities at December 31, 2000. Substantially
all of this amount was reclassified into earnings in 2001 as a component of gas
cost.
The Company recognized gains (losses) of approximately $0.1 million and
$(21.9) million, net of tax, as a result of qualifying cash flow hedges whose
hedged transactions occurred during the three and nine months ended September
30, 2002, respectively. The Company recognized losses of approximately $(7.4)
million and $(2.8) million, net of tax, as a result of qualifying cash flow
hedges whose hedged transactions occurred during the three and nine months ended
September 30, 2001, respectively. These gains and losses were recorded in cost
of gas. The Company estimates that most of the September 30, 2002 unrealized
gain balance of $2.2 million, net of tax, will be reclassified from accumulated
other comprehensive loss to earnings in 2002 as a decrease to realized gas cost
if market prices remain stable. As of September 30, 2002 all of the Company's
cash flow hedges settle by their terms before the end of 2005.
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 regulatory 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 and was insignificant in the periods presented.
Interest Rates
In May 2001 the Company entered into an interest rate swap agreement to
pay variable rate and receive fixed rate interest payments on a notional amount
of $300 million. This swap was designated as a fair value hedge of the $300
million medium-term notes also issued in May 2001. The swap agreement was
terminated and replaced with another swap agreement to pay variable rate and
receive fixed rate interest payments, also designated as a fair value hedge, in
August 2001. In August 2001 the Company received $6.5 million to terminate the
original swap. The $6.5 million basis adjustment of the related debt is being
amortized as a reduction to interest expense over the ten-year term of the $300
million medium-term notes. At September 30, 2002 the estimated fair value of the
new swap was $44.1 million.
In December 2001 PSNC entered into two interest rate swap agreements to
pay variable rate and receive fixed rate interest payments on a combined
notional amount of $44.9 million. These swaps were designated as fair value
hedges of PSNC's $12.9 million, 10 percent senior debenture due 2004 and $32.0
million, 8.75 percent senior debenture due 2012. At September 30, 2002 the
estimated fair value of these swaps was $3.3 million.
The fair value of these 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. The receipts or payments related to the interest
rate swaps are credited or charged to interest expense as incurred.
6. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 13 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001. Commitments and contingencies at September 30, 2002
include the following:
A. Lake Murray Dam Reinforcement
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in
order to 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 $250 million and be completed in 2005.
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.
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 primarily 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 $19.7
million at September 30, 2002. The deferral includes the estimated costs
associated with the following matters.
In September 1992 the Environmental Protection Agency (EPA) notified
SCE&G, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of SCE&G's decommissioned MGPs.
Field work at the site began in November 1993 and has required the submission of
several investigative reports and the implementation of several work plans. In
September 2000, SCE&G was notified by the South Carolina Department of Health
and Environmental Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park area site.
The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility
Study on the intermediate aquifer, which was completed in June 2001. The EPA
issued a Record of Decision dealing with the intermediate aquifer and sediments
in October 2002. The Record of Decision affirmed SCE&G's proposed remediation
approach. A Remedial Design Work Plan will be prepared by SCE&G by early 2003
for agency input and concurrence. SCE&G anticipates that the remaining
remediation activities will be implemented in 2003, with certain monitoring and
retreatment activities continuing until 2007. As of September 30, 2002, SCE&G
has spent approximately $18.8 million to remediate the Calhoun Park area 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 $2.1
million related to these sites and expects to spend an additional $5.9 million.
Public Service Company of North Carolina, Incorporated
PSNC owns, or has owned, all or portions of seven sites in North
Carolina on which MGPs were formerly operated. Intrusive investigation
(including drilling, sampling and analysis) has begun at two sites and the
remaining sites have been evaluated using historical records and observations of
current site conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. PSNC's associated actual costs for
these sites will depend on a number of factors, such as actual site conditions,
third-party claims and recoveries from other potentially responsible parties
(PRPs). In September 2002 an allocation agreement was reached relieving PSNC of
liability for two of the seven sites. PSNC has recorded a liability and
associated regulatory asset of $8.0 million, which reflects the estimated
remaining liability at September 30, 2002. Amounts incurred to date that have
not been recovered through gas rates are approximately $1.1 million. Management
believes that all MGP cleanup costs will be recoverable through gas rates.
D. Long-Term Natural Gas Contract
During 2001 the Company entered into a 15 year take-and-pay contract
(2004-2019) for the purchase of 190,000 DT/day of natural gas. The last
condition precedent to the contract was fulfilled during the third quarter 2002.
All of the natural gas requirements of the new Jasper generating plant,
scheduled to be operational in 2004, will be provided by this contract. The
Jasper generating plant average usage (on an annual basis) is expected to
approximate 77,600 DT/day. Natural gas not required by the Jasper plant will be
otherwise used by the Company and/or marketed to commercial and industrial
customers.
7. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The
Company uses operating income to measure profitability for its regulated
operations. Therefore, net income is not allocated to the Electric Operations,
Gas Distribution and Gas Transmission segments. The Company uses net income to
measure profitability for its Retail Gas Marketing and Energy Marketing
segments. Affiliate revenue is derived from transactions between reportable
segments as well as transactions between separate legal entities that are
combined into the same reportable segment. Accumulated depreciation is not
assignable to Electric Operations and Gas Distribution segments. Gas
Distribution is comprised of the local distribution operations of SCE&G and PSNC
and meets SFAS 131 criteria for aggregation.
Disclosure of Reportable Segments
(Millions of dollars)
- ---------------------------------- ------------- -------------- --------------- -----------------
Three Months Ended External Intersegment Operating Net
September 30, 2002 Revenue Revenue Income (Loss) Income (Loss)
- ---------------------------------- ------------- -------------- --------------- -----------------
Electric Operations $424 $166 $166 n/a
Gas Distribution 85 1 (12) n/a
Gas Transmission 51 54 6 n/a
Retail Gas Marketing 106 - n/a $(2)
Energy Marketing 28 - n/a (1)
Telecommunications Investments - - - (1)
All Other - 2 - (1)
Adjustments/Eliminations - (223) (6) 83
- ---------------------------------- ------------- -------------- --------------- -----------------
Consolidated Total $694 - $154 $78
================================== ============= ============== =============== =================
- ------------------------------------ ------------ -------------- ---------------- -----------------
Three Months Ended External Intersegment Operating Net
September 30, 2001 Revenue Revenue Income (Loss) Income (Loss)
- ------------------------------------ ------------ -------------- ---------------- -----------------
Electric Operations $416 $163 $154 n/a
Gas Distribution 90 1 (14) n/a
Gas Transmission 43 33 5 n/a
Retail Gas Marketing 116 - n/a $(2)
Energy Marketing 45 - n/a -
Telecommunications Investments - - - (3)
All Other - - - (3)
Adjustments/Eliminations - (197) (2) 71
- ------------------------------------ ------------ -------------- ---------------- -----------------
- ------------------------------------ ------------ -------------- ---------------- -----------------
Consolidated Total $710 - $143 $63
==================================== ============ ============== ================ =================
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Nine Months Ended External Intersegment Operating Net Segment
September 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Electric Operations $1,075 $459 $339 n/a $5,359
Gas Distribution 428 1 40 n/a 1,602
Gas Transmission 159 185 3 n/a 305
Retail Gas Marketing 403 - n/a $12 74
Energy Marketing 100 - n/a (4) 43
Telecommunications Investments - - - (154) 341
All Other - 5 - 2 291
Adjustments/Eliminations - (650) 14 190 (436)
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Consolidated Total $2,165 - $396 $46 $7,579
============================================ ============== =============== ================= ===============
- -------------------------------------------- --------------- ---------------- ---------------- --------------
Nine Months Ended External Intersegment Operating Net Segment
September 30, 2001 Revenue Revenue Income Income Assets
- -------------------------------------------- --------------- ---------------- ---------------- --------------
Electric Operations $1,097 $435 $345 n/a $4,878
Gas Distribution 600 1 39 n/a 1,579
Gas Transmission 176 199 9 n/a 313
Retail Gas Marketing 500 - n/a 5 96
Energy Marketing 396 - n/a 5 94
Telecommunications Investments - - - 347 729
All Other - - - (10) 431
Adjustments/Eliminations - (635) 17 180 (580)
- -------------------------------------------- --------------- ---------------- ---------------- --------------
- -------------------------------------------- --------------- ---------------- ---------------- --------------
Consolidated Total $2,769 - $410 $527 $7,540
============================================ =============== ================ ================ ==============
============================================ =============== ================ ================ ==============
8. SUBSEQUENT EVENTS
A. On October 15, 2002 SCE&G transferred its transit system to the City
of Columbia, South Carolina (City). As part of the transfer agreement, SCE&G
will pay the City $32 million over seven years in exchange for a 30-year
electric and gas franchise, has conveyed transit-related property and equipment
to the City and has conveyed the historic Columbia Canal and Hydroelectric Plant
to the City. SCE&G will also pay the Central Midlands Regional Transit Authority
up to $3 million as matching funds for Federal Transit Administration grants for
the purchase of new transit coaches and a new transit facility.
B. On October 16, 2002 the Company sold 6 million shares of common
stock and received net proceeds of approximately $146 million. On October 17,
2002 the Company made an equity contribution to SCE&G of $150 million.
C. On November 8, 2002 the South Carolina Jobs - Economic Development
Authority (JEDA) issued, and SCE&G received the proceeds of, an aggregate of
$90.4 million principal amount of Industrial Revenue Bonds Series 2002A and
2002B (the Bonds). The Bonds bear interest at rates ranging from 4.2 percent to
5.45 percent, with maturities ranging from 2012 to 2032. Proceeds from the Bonds
will be used to refund an aggregate amount of $62.3 million principal amount of
Pollution Control Revenue Bonds and to pay the costs of solid waste disposal
facilities at two of SCE&G's electric generating plants.
D. On November 6, 2002 SCH sold 275,000 ordinary shares of DTAG at a
price of approximately $12.50 per share. The sale resulted in net after-tax
proceeds of approximately $2.8 million. In addition, SCH determined that the
decline in value of its investment in DTAG to below its cost basis of $14.09 per
share was other than temporary, and will record an impairment loss of
approximately $18.9 million (after-tax) in the fourth quarter 2002.
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, 2001.
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 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 2002 and
2003. Further, while several companies have announced their intent to site
merchant generating plants in the Company's service territory, economic events,
environmental concerns and other factors have slowed those efforts. At the
Federal level, energy legislation has passed both houses of Congress in 2002,
though significant differences exist between the House and Senate versions.
Among other things, this legislation would require that one percent of the
electric energy sold by retail electric suppliers be generated from renewable
energy resources beginning in 2005. This requirement would escalate to ten
percent in 2019. Substantial penalties would be levied for failure to comply.
Electric cooperatives and municipal utilities would be exempt from these
requirements.
In June 2002 the Company and the other two electric utilities that
formed GridSouth Transco LLC (GridSouth) suspended implementation of GridSouth.
Though the three companies continue to support the regional transmission
organization (RTO) concept, GridSouth implementation was suspended pending the
issuance and evaluation of new FERC directives. In July 2002 FERC issued a
Notice of Proposed Rulemaking (NOPR) on Standard Market Design 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. While it is anticipated that
significant change to the NOPR may occur and that implementation, presently
scheduled for September 2004, may not occur for some time, any rules
standardizing the markets may have significant impact on the Company's access to
or cost of power for its native load customers and on the Company's marketing of
power outside its service territory. The Company is currently evaluating this
NOPR to determine what effect it will have on the Company's operations.
Additional directives from FERC are expected later in 2002.
The Company is not able to predict whether the preceding or similar
legislative or regulatory actions will be enacted and, if they are, the impact
they will have on the Company.
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 is expected to begin in early 2003, with completion
expected in the fall of 2003.
Retail Gas Marketing
In April 2002 Georgia's Governor signed into law the Natural Gas
Consumer's Relief Act of 2002 (the Act). The Act attempts to resolve many of the
issues surrounding Georgia's deregulated natural gas market with the following
significant provisions:
o creates a regulated provider selected through a bidding process to serve
low-income and high credit risk customers, o allows Georgia's 42 non-profit
Electric Membership Corporations (EMCs) to establish natural gas affiliates that
may seek
certification as marketers of natural gas,
o establishes new service quality standards and addresses assignment of
interstate assets, and o gives the Georgia Public Service Commission (GPSC) the
authority to temporarily regulate rates if more than
90% of customers in a specific area of the state are served by
three or fewer marketers.
The GPSC is responsible for implementing and monitoring most of the
Act's provisions. While SCANA Energy believes the Act represents a balanced
approach in addressing deregulation issues for consumers and marketers, the
impact the Act will have on SCANA Energy and Georgia's natural gas market cannot
be predicted until more details of GPSC's implementation become known.
In June 2002 SCANA Energy won GPSC approval to become the State's
regulated provider. In this capacity, SCANA Energy will serve low-income
customers generally at below-market rates, subsidized by Georgia's Universal
Service Fund, and it will extend service generally at above-market rates to high
credit risk customers who have been denied service by other marketers. SCANA
Energy began serving these customers on September 1, 2002.
In June 2002 the fourth largest marketer in Georgia's natural
gas market declared bankruptcy. In July 2002 a subsidiary of Southern Company
completed its purchase of the bankrupt marketer's Georgia operations. Southern
Company, through a subsidiary, sells electricity to approximately two million
customers in Georgia. Southern Company is anticipated to be a significant
competitor in the Georgia natural gas market. In addition, an affiliate of one
EMC has been certified by the GPSC as a gas marketer, and the application of
another EMC is pending. At October 31, 2002 the top three marketers (which
includes SCANA Energy) served approximately 80% of Georgia's natural gas market.
SCANA Energy and SCANA's other natural gas distribution, transmission
and marketing segments maintain gas inventory and also utilize forward contracts
and financial instruments, including futures contracts, to manage their exposure
to fluctuating commodity natural gas prices. (See Note 5 of Notes to Condensed
Consolidated Financial Statements.) As a part of this risk management process, 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 the 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's contractual cash obligations as of September 30, 2002 are
summarized below.
Contractual Cash Obligations
4th Quarter After
September 30, 2002 Total 2002 1-3 years 4-5 years 5 years
- ------------------ ----- ---- --------- --------- -------
(Millions of Dollars)
Long-term and short-term debt
(including interest) $5,761 $310 $1,397 $471 $3,583
Preferred stock sinking funds 10 - 2 1 7
Capital leases 3 - 3 - -
Operating leases 88 4 46 20 18
Other commercial commitments 6,835 445 1,818 709 3,863
Included in other commercial commitments are estimated obligations
under forward contracts for natural gas purchases. Many of these forward
contracts for natural gas purchases include customary "make-whole" or default
provisions, but are not considered to be "take-or-pay" contracts. Also included
in other commercial commitments is a "take-and-pay " contract for 190,000 DT/day
of natural gas for 15 years, beginning in 2004. This contract will supply the
new Jasper generating plant's natural gas requirement, which is expected to
average (on an annual basis) 77,600 DT/day. The balance of the natural gas
purchases under this contract will be otherwise used by the Company and/or
marketed to commercial and industrial customers. Certain of these contracts
relate to regulated businesses; therefore, the effects of such contracts on fuel
costs are reflected in electric or gas rates.
The Company anticipates that its contractual cash obligations will be
met through internally generated funds, the incurrence of additional short-term
and long-term indebtedness and sales of additional equity securities. See Notes
3 and 8 of Notes to Condensed Consolidated Financial Statements. 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 September 30, 2002 (including
the effects of nonrecurring impairment charges) was 1.34.
On August 6, 2002 SCE&G filed an application with the Public Service
Commission of South Carolina (SCPSC) requesting a $104.7 million increase in
retail electric revenues. The electric rate request is largely associated with
the power generation projects recently completed at Urquhart Station and the
Jasper County Generating Station currently under construction, both of which are
discussed below. The rate request also includes costs for equipment required for
environmental and air quality improvements.
The following table summarizes how the Company generated and used funds
for property additions and construction expenditures during the nine months
ended September 30, 2002 and 2001:
- --------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2002 2001
- ---------------------------------------------------------------------------
Net cash provided from operating activities $350 $270
Net cash provided from (used for) financing
activities (242) 74
Cash provided from sale of investments and assets 335 28
Funds used for investments (25) (43)
Cash and temporary investments available at
the beginning of the period 212 159
- ---------------------------------------------------------------------------
- ---------------------------------------------------------------------------
Net cash available for property additions
and construction expenditures $630 $488
===========================================================================
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $424 $311
Funds used for nonutility property additions 12 35
===========================================================================
CAPITAL TRANSACTIONS
On January 31, 2002 SCANA issued $250 million of medium-term notes
maturing February 1, 2012 and bearing a fixed interest rate of 6.25 percent.
Also on January 31, 2002 SCANA issued $150 million of two-year floating rate
notes maturing February 1, 2004. The interest rate on the floating rate notes is
reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from
these issuances were used to refinance $400 million of two-year floating rate
notes that matured February 8, 2002, which had been issued to finance SCANA's
acquisition of PSNC.
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem on
March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds, 8 7/8
percent Series due August 15, 2021.
On April 24, 2002 SCANA redeemed $202 million of floating rate
medium-term notes that were set to mature January 24, 2003. The notes were
bearing interest at a rate of 2.90 percent at the time of redemption.
On July 15, 2002 SCANA retired at maturity $300 million of floating rate
medium-term notes. The notes were bearing interest at a rate of 4.063 percent at
maturity.
On August 15, 2002 SCANA issued $100 million one-year floating rate
medium-term notes maturing August 15, 2003. The interest rate on the notes is
reset quarterly based on three-month LIBOR plus 87.5 basis points. The proceeds
were used for general corporate purposes.
On October 16, 2002 SCANA sold 6 million shares of common stock and
received net proceeds of approximately $146 million. On October 17, 2002 SCANA
made an equity contribution to SCE&G of $150 million.
On November 8, 2002 the South Carolina Jobs - Economic Development
Authority (JEDA) issued, and SCE&G received the proceeds of, an aggregate of
$90.4 million principal amount of Industrial Revenue Bonds Series 2002A and
2002B (the Bonds). The Bonds bear interest at rates ranging from 4.2 percent to
5.45 percent, with maturities ranging from 2012 to 2032. Proceeds from the Bonds
will be used to refund an aggregate amount of $62.3 million principal amount of
Pollution Control Revenue Bonds and to pay the costs of solid waste disposal
facilities at two of SCE&G's electric generating plants.
CAPITAL PROJECTS
SCE&G placed in service a $248 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 340 megawatts of new electric generation and use exhaust
heat to replace coal-fired steam that powers two existing 75 megawatt turbines
at the Urquhart Generating Station.
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 the summer of 2004. SCG
will transport natural gas to the facility (See discussion at Note 6D of Notes
to Condensed Consolidated Financial Statements). In connection with the
facility, SCE&G has signed an electric supply contract with North Carolina
Electric Membership Corporation to supply 350 megawatts in each of 2004 and 2005
and 250 megawatts annually in 2006 through 2012.
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 $250
million and be completed in 2005.
SECURITIES RATINGS (As of September 30, 2002)
SCANA SCE&G PSNC
- ---------------------------------------------- --------------------------------------- --- ----------------------
- -------------------------------------- --------------------------------- ------------------------ ---------------
First and
Medium- First Refunding Trust
Rating Term Mortgage Mortgage Preferred Preferred Commercial Senior Commercial
Agency Notes Bonds Bonds Stock Securities Paper Unsecured Paper
------ ----- ----- ----- ----- ---------- ----- --------- -----
Moody's A3 A1 A1 Baa1 A3 P-1 A2 P-1
Standard & Poor's BBB+ A- A- BBB BBB A-1 A- A-1
Fitch Ratings A- A+ A+ A A F-1 n/a n/a
- -------------------------------------- --------------------------------- ------------------------ ---------------
The ratings above reflect Standard & Poor's one-notch downgrade in July
2002. The Company does not expect the downgrade to adversely impact its
liquidity.
ENVIRONMENTAL MATTERS
For information on environmental matters see Note 6C of Notes to
Condensed Consolidated Financial Statements.
OTHER MATTERS
Radio Service Network
In April 2002 SCI sold its 800 Mhz radio service network within South
Carolina to Motorola, Inc. for an after-tax gain of approximately $9 million.
Telecommunications Investments
In June 2002 ITC^DeltaCom, Inc. (ITCD) announced plans for a
reorganization and entered into Chapter 11 bankruptcy. As a result the Company
and SCANA Communications Holdings, Inc. (SCH) wrote off their investments in
ITCD in the second quarter and recorded an aggregate impairment charge of
approximately $7.0 million (after tax). The bankruptcy court accepted the
reorganization plan, and ITCD emerged from bankruptcy on October 29, 2002. In
connection with ITCD's emergence from bankruptcy, SCH provided $15 million in
preferred equity financing.
In July 2002 Knology Inc. (Knology) negotiated a potential exchange of
its discount notes for a combination of new notes and new preferred stock. In
contemplation of the anticipated exchange, the Company recorded an impairment
loss of approximately $0.3 million (after-tax) in the second quarter. Because
the exchange offer did not result in the requisite minimum tender of notes, in
the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which
reflected the same terms of exchange. The bankruptcy court accepted the
reorganization plan, and in connection with Knology's emergence from bankruptcy,
SCH purchased an additional 6.5 million shares of series C preferred stock for
approximately $19.5 million on November 6, 2002.
On November 6, 2002 SCH sold 275,000 ordinary shares of DTAG at a price
of approximately $12.50 per share. The sale resulted in net after-tax proceeds
of approximately $2.8 million. In addition, SCH determined that the decline in
value of its investment in DTAG to below its cost basis of $14.09 per share was
other than temporary, and will record an impairment loss of approximately $18.9
million (after-tax) in the fourth quarter 2002.
For more information on telecommunications investments, see Note 5 of
Notes to Condensed Consolidated Financial Statements.
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. If approved, the extension would allow the plant to operate through
2042.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over seven years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the historic Columbia Canal and Hydroelectric Plant to the
City. SCE&G will also pay the Central Midlands Regional Transit Authority up to
$3 million as matching funds for Federal Transit Administration grants for the
purchase of new transit coaches and a new transit facility.
Stock Purchase-Savings Plan
Between April 17, 2002 and August 1, 2002, 265,814 shares of the
Company's no par value common stock ("Common Stock") were purchased in open
market transactions by AMVESCAP National Trust Company as Trustee of the
Company's Stock Purchase-Savings Plan (the Plan). These shares were purchased
for the accounts of those employees of the Company and its subsidiaries that
participate in the Plan. Under the terms of the Plan, employees may contribute
up to 15% of their "eligible earnings" to the Plan and the Company matches the
first 6% of such contributions on a dollar-for-dollar basis. The Company
believes that the open market purchase of shares by the Trustee should not be
deemed to be an offer or sale of securities subject to the registration
requirements of the Securities Act of 1933, as amended. Nevertheless, the
Company filed a registration statement on August 2, 2002, on Form S-8
(333-97555) registering 5,000,000 shares of Common Stock for sale under the
Plan.
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002
AS COMPARED TO THE CORRESPONDING PERIOD IN 2001
Earnings Per Share
Earnings per share of common stock for the third quarter and year to
date periods ended September 30, 2002 and 2001 were as follows:
- ----------------------------------------------------------------------------------------------
Third Quarter Year to Date
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------
Earnings (loss) derived from:
Operations $.74 $.61 $1.84 $1.61
Non-recurring items:
Realized gain from stock investment - - .10 3.38
Sales of assets of subsidiaries - - .09 .04
Investment impairments - - (1.59) -
---------------
- ------------------------------------------------------------------------- ---------------
Earnings per weighted average share $.74 $.61 $.44 $5.03
========================================================================= ===============
Third Quarter 2002 vs 2001
Earnings per share from operations increased $.13 primarily due to
improved margins from the sale of electricity of $.15, lower interest expense of
$.02, lower depreciation and amortization expense of $.01, improved results from
non-regulated subsidiaries of $.01 and other increases of $.04. These factors
were partially offset by lower gas margins of $.03, higher operation and
maintenance expenses of $.06 and higher property taxes of $.01.
Year to Date 2002 vs 2001
Earnings per share from operations increased $.23 primarily due to
improved margins from sales of electricity of $.18, lower interest expense of
$.13, improved results from non-regulated subsidiaries of $.07, increased
allowance for funds used during construction of $.05, lower depreciation and
amortization expense of $.03 and other increases of $.02. These factors were
partially offset by lower gas margins of $.16 and higher operation and
maintenance expenses of $.09.
Earnings per share from non-recurring items includes a second quarter
2002 gain from the sale of the Company's radio service network of $.09 and loss
from an impairment charge related to the Company's investment in ITCD of $.07.
In addition, the Company recognized a non-recurring gain of $.10 per share in
connection with the sale of Deutsche Telekom AG (DTAG) ordinary 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 (see Note 5 of Notes to Condensed Consolidated
Financial Statements). In 2001 the Company recorded a gain from the sale of its
investment in Powertel, Inc. of $3.38 and a gain from the sale of the assets of
SCANA Security of $.04.
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 third quarter and the
year to date periods of 2002 decreased significantly compared to corresponding
periods in 2001 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:
- ------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 2002 2001
- ------------------------------------------------------------------------------
- --------------------------------------------------------------------- --------
Income Statement Impact:
Reduction in employee benefit costs $1.2 $6.3 $8.1 $16.7
Increase in other income 4.4 3.7 8.3 9.6
Balance Sheet Impact:
- --------------------------------------------------------------------- --------
Reduction in capital expenditures 0.4 1.7 2.3 4.6
- --------------------------------------------------------------------- --------
- --------------------------------------------------------------------- --------
Total Pension Income $6.0 $11.7 $18.7 $30.9
===================================================================== ========
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. Both the
equity and the debt portions of AFC are noncash items of nonoperating income
which have the effect of increasing reported net income. AFC represented
approximately 7 percent and 37 percent of income before taxes and preferred
stock dividends for the three and nine months ended September 30, 2002,
respectively, compared to approximately 7 percent and 2 percent, respectively,
for the corresponding periods in 2001. The increase in AFC is primarily the
result of increased construction expenditures related to the Urquhart Station
repowering project, the Jasper County Generating Station project and the Lake
Murray Dam project (see discussion at LIQUIDITY AND CAPITAL RESOURCES) and the
effect of non-recurring items on income before taxes for the year to date
periods.
Dividends Declared
The Company's Board of Directors declared the following dividends on
common stock during 2002:
- ------------------- ----------------------------------------- -----------------
Declaration Date Dividend Per Share Record Date Payment Date
- ------------------- ----------------------------------------- -----------------
February 21, 2002 $.325 March 8, 2002 April 1, 2002
May 2, 2002 $.325 June 10, 2002 July 1, 2002
August 1, 2002 $.325 September 10, 2002 October 1, 2002
October 31, 2002 $.325 December 10, 2002 January 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:
-----------------------------------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
---------------------------------------------------------------------------------------------------------
Electric operating revenue $424.2 $416.3 $7.9 1.9% $1,075.3 $1,097.0 $(21.7) (2.0%)
Less: Fuel used in generation 105.1 86.5 18.6 21.5% 271.0 221.7 49.3 22.2%
Purchased power 7.3 43.3 (36.0) (83.1%) 28.7 130.8 (102.1) (78.1%)
---------------------------------------------------------- --------------------------------
Margin $311.8 $286.5 $25.3 8.8% $775.6 $744.5 $31.1 4.2%
=============================================================================================================
Third Quarter 2002 vs 2001
Margin increased primarily due to more favorable weather ($14.7 million)
and customer growth ($12.8 million). Fuel used in generation increased and
purchased power decreased primarily due to completion of the Urquhart Station
repowering project in June 2002.
Year to Date 2002 vs 2001
Margin increased primarily due to more favorable weather ($14.7 million)
and customer growth ($19.3 million). Fuel used in generation increased and
purchased power decreased due to completion of the Urquhart Station repowering
project in June 2002 and more plants being on line during the period.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC. Changes in the gas distribution sales margins, including
transactions with affiliates, were as follows:
- --------------------------------------------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- --------------------------------------------------------------------------------------------------------------------
Gas distribution operating revenue $85.7 $90.3 $(4.6) (5.1%) $429.1 $600.8 $(171.7) (28.6%)
Less: Gas purchased for resale 53.9 58.1 (4.2) (7.2%) 254.9 425.8 (170.9) (40.1%)
- --------------------------------------------------------------- -------------------------------
Margin $31.8 $32.2 $(0.4) (1.2%) $174.2 $175.0 $(0.8) (0.5%)
==================================================================================================================
Third Quarter 2002 vs 2001
Margin decreased at PSNC ($1.1 million) due primarily to the slow North
Carolina economy, which was partially offset at SCE&G ($0.7 million) by an
improved competitive position relative to alternate fuels for interruptible
customers.
Year to Date 2002 vs 2001
Margins decreased primarily due to milder weather and weak economic
conditions in the first quarter ($3.8 million), which were partially offset by
customer growth ($1.6 million) and an improved competitive position relative to
alternate fuels for interruptible customers ($1.9 million). Revenues and gas
purchases decreased as a result of lower commodity natural gas prices in the
first and second quarters.
Gas Transmission
Gas Transmission is comprised of the operations of South Carolina
Pipeline Corporation. Changes in the gas transmission sales margins, including
transactions with affiliates, were as follows:
- --------------------------------------------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- --------------------------------------------------------------------------------------------------------------------
Gas transmission operating revenue $105.3 $76.2 $29.1 38.2% $344.3 $374.6 $(30.3) (8.1%)
Less: Gas purchased for resale 92.2 63.6 28.6 45.0% 319.1 342.3 (23.2) (6.8%)
- --------------------------------------------------------------- --------------------------------
Margin $13.1 $12.6 $0.5 4.0% $25.2 $32.3 $(7.1) (22.0%)
====================================================================================================================
Third Quarter 2002 vs 2001
Margin increased primarily due to the favorable competitive position of
natural gas relative to alternate fuels and increased sales for electric
generation.
Year to Date 2002 vs 2001
Margin decreased primarily due to the unfavorable competitive position
of natural gas relative to alternate fuels in the first quarter, which was
partially offset by a favorable competitive position in the second and third
quarters and increased sales for electric generation.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in Georgia's deregulated natural gas
market. Retail Gas Marketing also includes industrial sales in the state of
Georgia. Retail gas marketing revenues and net income, were as follows:
- ------------------------------------------------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $106.6 $116.0 $(9.4) (8.1%) $402.8 $500.0 $(97.2) (19.4%)
Net income (loss) $(2.4) $(1.9) $(0.5) (26.3%) $12.2 $4.8 $7.4 *
========================================================================================================================
*Greater than 100%
Third Quarter 2002 vs 2001
Operating revenues decreased primarily as a result of the decline in
commodity natural gas prices, lower volumes and fewer customers. Net loss
increased slightly primarily due to lower gas margins ($3.6 million) partially
offset by lower bad debt expense ($2.0 million) and lower interest expense ($0.9
million).
Year to Date 2002 vs 2001
Operating revenues decreased primarily as a result of the decline in
commodity natural gas prices, lower volumes and fewer customers. Net income
increased primarily due to lower bad debt expense ($11.9 million) and interest
costs ($2.7 million), which were partially offset by lower gas margins ($7.1
million).
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Changes in energy marketing operating
revenues, including transactions with affiliates, and net income (loss) were as
follows:
- ------------------------------------------------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $27.5 $45.1 $(17.6) (39.0%) $100.0 $396.7 $(296.7) (74.8%)
Net income (loss) $(2.6) $(0.3) $(2.3) * $(5.8) $4.8 $(10.6) *
========================================================================================================================
*Greater than 100%
Third Quarter 2002 vs 2001
Operating revenues decreased primarily as a result of the decline in
commodity natural gas prices. Net loss increased primarily as a result of higher
bad debt expense in 2002.
Year to Date 2002 vs 2001
Operating revenues decreased primarily as a result of the decline in
commodity natural gas prices and due to less favorable weather in the first and
second quarters. The change to a net loss in 2002 from net income in 2001
resulted primarily from the closing of operations of SCANA Energy Trading, LLC
during the first quarter of 2002 ($5.7 million), lower margins related to
decreased gas prices and decreased volumes in 2002 ($2.3 million), higher bad
debt expense in 2002 ($1.3 million) and lower interest earned on margin calls
($0.8 million).
Other Operating Expenses
Changes in other operating expenses were as follows:
- -----------------------------------------------------------------------------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- -----------------------------------------------------------------------------------------------------------------
Other operation and maintenance $125.4 $116.6 $8.8 7.5% $383.3 $367.7 $15.6 4.2%
Depreciation and amortization 55.0 56.4 (1.4) (2.5%) 163.4 168.3 (4.9) (2.9%)
Other taxes 31.6 29.4 2.2 7.5% 94.9 88.1 6.8 7.7%
- ------------------------------------------------------------ -------------------------------
Total $212.0 $202.4 $9.6 4.7% $641.6 $624.1 $17.5 2.8%
=================================================================================================================
Third Quarter 2002 vs 2001
Other operation and maintenance expenses increased primarily due to
reduced pension income ($5.1 million) and increased labor and benefits costs
($4.6 million). Depreciation and amortization decreased primarily due to
implementation of SFAS 142 and the resulting elimination of amortization expense
related to goodwill ($3.6 million-See Note 1B of Notes to Condensed Consolidated
Financial Statements) and normal net property changes ($0.2 million), which was
partially offset by increases for the completion of the Urquhart Station
repowering project in June 2002 ($2.4 million). Other taxes increased primarily
due to increased property taxes.
Year to Date 2002 vs 2001
Other operation and maintenance expenses increased primarily due to
reduced pension income ($8.6 million), increased labor and benefits costs ($9.9
million), increased nuclear refueling maintenance costs ($4.0 million),
increased costs at Cope Generating Station and Cogen South ($3.6 million) and
higher property insurance costs ($2.8 million), which were partially offset by
lower bad debt expense ($14.1 million). Depreciation and amortization expenses
decreased primarily due to implementation of SFAS 142 and the resulting
elimination of amortization expense related to goodwill ($10.7 million-See Note
1B of Notes to Condensed Consolidated Financial Statements), which was partially
offset by increases for the completion of the Urquhart Station repowering
project in June 2002 ($3.2 million) and normal net property additions ($2.6
million). Other taxes increased primarily due to increased property taxes.
Other Income (Loss)
Third Quarter and Year to Date 2002 vs 2001
Other income, including AFC, increased primarily due to construction at
Urquhart Station (completed in June 2002), Jasper County and Lake Murray Dam.
Other Income (Loss) related to the gain on sale of investments and assets and
the impairment of investments are discussed at Earnings Per Share.
Interest Expense
Third Quarter and Year to Date 2002 vs 2001
Interest expense decreased primarily due to declining interest rates on
the Company's debt ($14.0 million) and a reduction in long-term debt ($7.9
million).
Income Taxes
Third Quarter 2002 vs 2001
Income taxes increased primarily as a result of increased operating
income.
Year to Date 2002 vs 2001
Income taxes decreased primarily due to reductions of deferred income
taxes in connection with the non-recurring investment impairments recorded in
March and June 2002 arising from the Company's telecommunications investments
(see Note 5 of Notes to Condensed Consolidated Financial Statements), which were
partially offset in March and April 2002 by the sale of DTAG stock and the sale
of the Company's radio service network. Income taxes in 2002 also reflect
increased tax deductions related to dividends paid on stock held in the
Company's stock purchase savings plan.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held
for purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
As of September 30, 2002 Expected Maturity Date
- ------------------------ ----------------------
Millions of dollars
There- Fair
Liabilities 2002 2003 2004 2005 2006 after Total Value
- ----------------------------------- -------- ---------- ---------- --------- --------- ---------- --------- ---------------
- ----------------------------------- -------- ---------- ---------- --------- --------- ---------- --------- ---------------
Long-Term Debt:
Fixed Rate ($) 24.9 298.7 187.3 182.2 162.8 2,174.6 3,030.5 3,290.0
Average Fixed Interest Rate 4.30 6.37 7.57 7.43 8.63 6.79
6.91
Variable Rate ($) 100.0 150.0 - - 250.0
- 250.0
Average Variable Interest Rate 2.63 2.45 - -
- 2.52
Interest Rate Swap:
Pay Variable/Receive Fixed ($) - 12.9 - - 332.0 344.9 47.4
Average Pay Interest Rate - 7.73 - - 2.74
2.93
Average Receive Interest Rate - 10.00 - -
6.21 6.35
While a decrease in interest rates would increase the fair value of
debt, it is unlikely that events which would result in a realized loss will
occur.
In addition, at September 30, 2002 the Company had investments in the
11.875 percent senior discount notes (due 2007) of a telecommunications company,
the cost basis of which was approximately $82.1 million. See additional
discussion at Other Matters - Telecommunications Investments at Management's
Discussion and Analysis of Financial Condition.
Commodity price risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.
As of September 30, 2002
Millions of dollars, except weighted average settlement price and strike price
Natural Gas Derivatives: Expected Maturity in 2002 Expected Maturity in 2003
- -------------------------- --------------------------------- --------------------------------
Settlement Contract Fair Settlement Contract Fair
Price (a) Amount Value Price (a) Amount Value
Futures Contracts:
Long($) 4.24 24.7 33.4 4.27 35.6 45.5
Short($) 4.25 11.9 12.7 4.27 17.4 18.6
Strike Contract Strike Contract
Price Amount Price Amount
(a) (a)
Options:
Purchased call (long)($) 4.10 15.7 4.19 20.0
Sold put (long)($) 2.30 2.80 2.30 4.10
- -------------------------- ----------- --------------------- ----------- --------------------
(a) Weighted average
See Note 5 of Notes to Condensed Consolidated Financial Statements for
additional information.
The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of different types. Instruments
designated as cash flow hedges are used to hedge risks associated with fixed
price obligations in a volatile market and risks associated with price
differentials at different delivery locations. The basic types of financial
instruments utilized are exchange-traded instruments, such as NYMEX futures
contracts or options, and over-the-counter instruments such as swaps, which are
typically offered by energy and financial institutions.
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 the authority for setting market risk
limits to a Risk Management Committee, which is comprised of certain officers
and senior officers of the Company. The Risk Management Committee provides
assurance to the Board of Directors with regard to compliance with risk
management policies and brings to the Board's attention any areas of concern.
Written policies define the physical and financial transactions that are
approved, as well as the authorization requirements and limits for transactions
that are allowed.
The information in the table above includes those financial positions of
both Energy Marketing and SCPC. SCPC operates an SCPSC approved hedging program
designed to minimize volatility in natural gas prices. The ultimate effects of
the hedging activities of SCPC are passed through to its customers through
SCPC's weighted average cost of gas calculation.
Equity price risk - Investments in telecommunications companies' equity
securities 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 $198.1 million at September 30, 2002. A temporary decline in
value of ten percent would result in a $19.8 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 reduction
in fair value and a corresponding adjustment to net income, net of tax effect.
Item 4. Controls and Procedures
As of September 30, 2002, an evaluation was performed under the supervision
and with the participation of the Company's management, including the CEO and
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 the Company's disclosure
controls and procedures were effective as of September 30, 2002. There have been
no significant changes in the Company's internal controls or in other factors
that could significantly affect internal controls subsequent to September 30,
2002.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ----------------------------------------------------------------------------- -----------------------
ptember 30, December 31,
Millions of dollars 2002 2001
- ----------------------------------------------------------------------------- -----------------------
Assets
Utility Plant:
Electric $4,890 $4,563
Gas 435 425
Other 191 188
- ----------------------------------------------------------------------------- -----------------------
Total 5,516 5,176
Accumulated depreciation and amortization (1,923) (1,841)
- ----------------------------------------------------------------------------- -----------------------
Total 3,593 3,335
Construction work in progress 509 511
Nuclear fuel, net of accumulated amortization 44 45
- ----------------------------------------------------------------------------- -----------------------
Utility Plant, Net 4,146 3,891
- ----------------------------------------------------------------------------- -----------------------
Nonutility Property and Investments, Net 25 24
- ----------------------------------------------------------------------------- -----------------------
- ----------------------------------------------------------------------------- -----------------------
Current Assets:
Cash and temporary investments 80 78
Receivables 239 212
Receivables - affiliated companies 2 4
Inventories (at average cost):
Fuel 46 39
Materials and supplies 50 48
Emission allowances 11 13
Prepayments 14 6
- ----------------------------------------------------------------------------- -----------------------
Total Current Assets 442 400
- ----------------------------------------------------------------------------- -----------------------
Deferred Debits:
Environmental 20 24
Nuclear plant decommissioning fund 84 79
Pension asset, net 259 239
Due from affiliates - pension and postretirement benefits 16 15
Other regulatory assets 205 193
Other 107 97
- ----------------------------------------------------------------------------- -----------------------
Total Deferred Debits 691 647
- ----------------------------------------------------------------------------- -----------------------
Total $5,304 $4,962
============================================================================= =======================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------- --------------------
ptember 30, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------- --------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $1,814 $1,750
Preferred stock (Not subject to purchase or sinking funds) 106 106
- --------------------------------------------------------------------------------- --------------------
Total Stockholders' Investment 1,920 1,856
Preferred Stock, net (Subject to purchase or sinking funds) 9 10
Company-Obligated Mandatorily Redeemable Preferred Securities
of the Company's Subsidiary Trust, SCE&G Trust I, holding
solely $50 million principal amount of the 7.55%
Junior Subordinated Debentures of SCE&G, due 2027 50 50
Long-Term Debt, net 1,619 1,412
- --------------------------------------------------------------------------------- --------------------
Total Capitalization 3,598 3,328
- --------------------------------------------------------------------------------- --------------------
Current Liabilities:
Short-term borrowings 233 165
Current portion of long-term debt 30 28
Accounts payable 91 99
Accounts payable - affiliated companies 46 78
Customer deposits 22 19
Taxes accrued 69 80
Interest accrued 31 27
Dividends declared 42 42
Deferred income taxes, net 18 12
Other 7 8
- --------------------------------------------------------------------------------- --------------------
Total Current Liabilities 589 558
- --------------------------------------------------------------------------------- --------------------
Deferred Credits:
Deferred income taxes, net 607 599
Deferred investment tax credits 106 109
Reserve for nuclear plant decommissioning 84 79
Due to affiliates - pension and postretirement benefits 17 16
Postretirement benefits 129 122
Regulatory liabilities 105 81
Other 69 70
- --------------------------------------------------------------------------------- --------------------
Total Deferred Credits 1,117 1,076
- --------------------------------------------------------------------------------- --------------------
Total $5,304 $4,962
================================================================================= ====================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- ---------------------------------------------------------------- ------------------------- --------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars 2002 2001 2002 2001
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Operating Revenues:
Electric $425 $418 $1,079 $1,101
Gas 47 43 207 258
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Total Operating Revenues 472 461 1,286 1,359
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Operating Expenses:
Fuel used in electric generation 86 69 217 174
Purchased power (including affiliated purchases) 36 70 111 206
Gas purchased for resale 36 33 148 198
Other operation and maintenance 89 78 269 241
Depreciation and amortization 43 41 126 122
Other taxes 27 25 81 75
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Total Operating Expenses 317 316 952 1,016
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Operating Income 155 145 334 343
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Other Income:
Other Income, Including Allowance for Equity Funds
Used During Construction of $5, $3, $16 and $7 9 6 28 20
Gain on sale of assets - 1 - 2
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Total Other Income 9 7 28 22
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 164 152 362 365
Interest Charges, Net of Allowance for Borrowed
Funds Used During Construction of $3, $3, $10 and $7 30 26 87 82
Preferred Dividend Requirement of the Company -
Obligated Mandatorily Redeemable Preferred Securities 1 1 3 3
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Income Before Income Taxes and Preferred Stock Dividends 133 125 272 280
Income Taxes 47 45 94 103
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Net Income 86 80 178 177
Preferred Stock Cash Dividends Declared (At stated rates) 2 2 6 6
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Earnings Available for Common Stockholder $84 $78 $172 $171
================================================================ ============ ============ ============= ============
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -------------------------------------------------------------------------------------------- ----------------------------
Nine Months Ended
September 30,
Millions of dollars 2002 2001
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash Flows From Operating Activities:
Net income $178 $177
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization 127 122
Amortization of nuclear fuel 14 11
Allowance for funds used during construction (26) (14)
Gain on sale of assets - (2)
Over (under) collections, fuel adjustment clauses (14) 3
Changes in certain assets and liabilities:
(Increase) decrease in receivables (25) 48
(Increase) decrease in inventories (7) (1)
(Increase) decrease in prepayments (8) (4)
(Increase) decrease pension asset (20) (32)
(Increase) decrease other regulatory assets 2 (4)
Increase (decrease) deferred income taxes, net 14 12
Increase (decrease) other regulatory liabilities 32 19
Increase (decrease) postretirement benefits 7 6
Increase (decrease) in accounts payable (40) (82)
Increase (decrease) in taxes accrued (11) 51
Increase (decrease in interest accrued 4 7
Changes in other assets (25) (15)
Changes in other liabilities 13 9
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Provided From Operating Activities 215 311
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (362) (263)
Proceeds from sales of assets 1 3
Nonutility property additions (2) (2)
Investments (7) (5)
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Used For Investing Activities (370) (267)
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149
Capital contribution from parent 5 25
Repayments:
First and Refunding Mortgage Bonds (104) -
Other long-term debt (3) (3)
Retirement of Preferred Stock (1) -
Dividends and distributions:
Common stock (113) (119)
Preferred stock (6) (6)
Short-term borrowings, net 84 (113)
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Provided From (Used For) Financing Activities 157 (67)
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Increase (Decrease) In Cash and Temporary Investments 2 (23)
Cash and Temporary Investments, January 1 78 60
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash and Temporary Investments, September 30 $80 $37
============================================================================================ ============= ==============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $10 and $7 ) $82 $74
- Income taxes 54 11
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2002
(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, 2001. 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 September 30, 2002 approximately $225 million and $105 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets, and liabilities of approximately $125 million and
$97 million, respectively. The electric and gas regulatory assets of
approximately $51 million and $49 million, respectively (excluding deferred
income tax assets), are recoverable through rates. The Public Service Commission
of South Carolina (SCPSC) has reviewed and approved most of the items shown as
regulatory assets through specific orders. Other items represent costs which are
not yet approved for recovery by the SCPSC, but are the subject of current or
future filings. In recording these costs as regulatory assets, management
believes the costs will be allowable under existing rate-making concepts that
are embodied in current 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
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing liabilities related to the future
obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective
January 1, 2003. The impact SFAS 143 may have on the Company's financial
position has not been determined but could be material particularly in regards
to the V. C. Summer Nuclear Station (Summer Station). The Company does not
expect that any other ARO liability would be material or subject to accrual due
to uncertainty of timing of cash flows. Because any ARO anticipated to be
recorded would relate to regulated operations, it is not expected that the
initial adoption of the statement will have any impact on results of operations
or cash flows.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" became effective January 1, 2002. This statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The
provisions of SFAS 145, among other things, discontinue treating gains or losses
from the early extinguishment of debt as extraordinary items unless such early
extinguishment meets the criteria of Accounting Principles Board Opinion No. 30.
The Company will adopt SFAS 145 effective January 1, 2003 and does not expect
that such initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. 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.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that such initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
Electric
On August 6, 2002 the Company filed an application with the SCPSC
requesting a $104.7 million increase in retail electric revenues. The electric
rate request is largely associated with the power generation projects recently
completed atUrquhart Station and the Jasper County Generating Station currently
under construction. It also includes costs for equipment required for
environmental and air quality improvements. Hearings on this request are to be
held in late November 2002, with an order expected in February 2003.
In April 2002 the SCPSC approved the Company's request to increase the fuel
component of rates charged to electric customers from 1.579 cents per
kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2002 through April 2003. The increase
also provides recovery for under-collected actual fuel costs through April 2002,
including short-term purchased power costs necessitated by outages at two of the
Company's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002.
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, 2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-September 2002
On October 22, 2002 as part of the annual review of gas costs, the SCPSC
approved the Company's request to increase the cost of gas component from $.596
per therm to $.728 per therm effective with the first billing cycle in November
2002.
In 1994 the SCPSC issued an order approving the Company's request to
recover, through a billing surcharge to its gas customers, the costs of
environmental cleanup at the sites of former manufactured gas plants (MGPs). The
billing surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for the Company's gas operations that had
previously been deferred. In October 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 of the balance remaining at September
30, 2002 ($19.7 million) prior to the end of 2005.
3. LONG-TERM DEBT
On January 31, 2002 the Company issued $300 million of first mortgage
bonds having an annual interest rate of 6.625 percent and maturing February 1,
2032. The proceeds from the sale of these bonds were used to reduce short-term
debt primarily incurred as a result of the Company's construction program and to
redeem on March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds,
8 7/8 percent Series due August 15, 2021.
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 September 30, 2002 approximately $40 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 12 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001. Commitments and Contingencies at September 30, 2002
include the following:
A. Lake Murray Dam Reinforcement
In October 1999 the Federal Energy Regulatory Commission (FERC) mandated
that the Company reinforce its Lake Murray dam in order to 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 $250 million and be completed in 2005.
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 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 primarily to regulated operations.
Such amounts are deferred and amortized with recovery provided through
rates. Deferred amounts, net of amounts previously recovered through rates and
insurance settlements, totaled $19.7 million at September 30, 2002. The deferral
includes the estimated costs associated with the following matters.
In September 1992 the Environmental Protection Agency (EPA) notified the
Company, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of the Company's decommissioned
MGPs. Field work at the site began in November 1993 and has required the
submission of several investigative reports and the implementation of several
work plans. In September 2000, the Company was notified by the South Carolina
Department of Health and Environmental Control (DHEC) that benzene contamination
was detected in the intermediate aquifer on surrounding properties of the
Calhoun Park area site. The EPA required that the Company conduct a focused
Remedial Investigation/Feasibility Study on the intermediate aquifer, which was
completed in June 2001. The EPA issued a Record of Decision dealing with the
intermediate aquifer and sediments in October 2002. The Record of Decision
affirmed the Company's proposed remediation approach. A Remedial Design Work
Plan will be prepared by the Company by early 2003 for agency input and
concurrence. The Company anticipates that the remaining remediation activities
will be implemented in 2003, with certain monitoring and retreatment activities
continuing until 2007. As of September 30, 2002, the Company has spent
approximately $18.8 million to remediate the Calhoun Park area 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 $2.1 million related to these sites and expects to spend an
additional $5.9 million.
6. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The
Company uses operating income to measure profitability for its regulated
operations. Therefore, net income is not allocated to the Electric Operations
and Gas Distribution segments. Affiliate revenue is derived from transactions
between reportable segments as well as transactions between separate legal
entities that are combined into the same reportable segment. Accumulated
depreciation is not assignable to Electric Operations and Gas Distribution
segments.
Disclosure of Reportable Segments
(Millions of Dollars)
- ------------------------------------------- -------------- ----------------
Three months ended External Intersegment Operating
September 30, 2002 Revenue Revenue Income (Loss)
- ------------------------------------------- -------------- ----------------
Electric Operations $425 $64 $162
Gas Distribution 47 1 (6)
All Other - - -
Adjustments/Eliminations - (65) (1)
- ------------------------------------------- -------------- ----------------
- ------------------------------------------- -------------- ----------------
Consolidated Total $472 - $155
=========================================== ============== ================
- ---------------------------------------------- ------------- -----------------
Three months ended External Intersegment Operating
September 30, 2001 Revenue Revenue Income (Loss)
- ---------------------------------------------- ------------- -----------------
Electric Operations $418 $66 $151
Gas Distribution 43 - (5)
All Other - - -
Adjustments/Eliminations - (66) (1)
- ---------------------------------------------- ------------- -----------------
- ------------------------------------ ------------- -----------------
Consolidated Total $ 461 - $145
============================================ ============= =================
- --------------------------------- -------------- -------------- -----------
Nine months ended External Intersegment Operating Segment
September 30, 2002 Revenue Revenue Income (Loss) Assets
- ------------------------------------------ ------------- ---------------- ----
Electric Operations $1,079 $170 $329 $5,359
Gas Distribution 207 2 6 440
All Other - - - 4
Adjustments/Eliminations - (172) (1) (499)
- ------------------------------------------------------------------- -----------
- ------------------------------------------------------------------- -----------
Consolidated Total $1,286 - $334 $5,304
=================================================================== ===========
- ---------------------------------- --------------- -------------- -----------
Nine months ended External Intersegment Operating Segment
September 30, 2001 Revenue Revenue Income (Loss) Assets
- ---------------------------------- --------------- -------------- -----------
Electric Operations $1,101 $165 $334 $4,878
Gas Distribution 258 - 12 427
All Other - - - 5
Adjustments/Eliminations - (165) (3) (515)
- ------------------------------------ --------------- ---------------- ---------
Consolidated Total $1,359 - $343 $4,795
==================================== =============== ================ =========
7. SUBSEQUENT EVENTS
A. On October 15, 2002 the Company transferred its transit system to
the City of Columbia, South Carolina (City). As part of the transfer agreement,
the Company will pay the City $32 million over seven years in exchange for a
30-year electric and gas franchise, has conveyed transit-related property and
equipment to the City and has conveyed the historic Columbia Canal and
Hydroelectric Plant to the City. The Company will also pay the Central Midlands
Regional Transit Authority up to $3 million as matching funds for Federal
Transit Administration grants for the purchase of new transit coaches and a new
transit facility.
B. On October 17, 2002 the Company received an equity contribution
of $150 million from SCANA Corporation.
C. On November 8, 2002 the South Carolina Jobs - Economic Development
Authority (JEDA) issued, and the Company received the proceeds of, an aggregate
of $90.4 million principal amount of Industrial Revenue Bonds Series 2002A and
2002B (the Bonds). The Bonds bear interest at rates ranging from 4.2 percent to
5.45 percent, with maturities ranging from 2012 to 2032. Proceeds from the Bonds
will be used to refund an aggregate amount of $62.3 million principal amount of
Pollution Control Revenue Bonds and to pay the costs of solid waste disposal
facilities at two of the Company's electric generating plants.
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, 2001.
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 SEC. SCE&G disclaims any
obligation to update any forward-looking statements.
COMPETITION
In South Carolina electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2002 and
2003. Further, while several companies have announced their intent to site
merchant generating plants in the Company's service territory, economic events,
environmental concerns and other factors have slowed those efforts. At the
Federal level, energy legislation has passed both houses of Congress in 2002,
though significant differences exist between the House and Senate versions.
Among other things, this legislation would require that one percent of the
electric energy sold by retail electric suppliers be generated from renewable
energy resources beginning in 2005. This requirement would gradually escalate to
ten percent in 2019. Substantial penalties would be levied for failure to
comply. Electric cooperatives and municipal utilities would be exempt from these
requirements.
In June 2002 the Company and the other two electric utilities that
formed GridSouth Transco LLC (GridSouth) suspended implementation of GridSouth.
Though the three companies continue to support the regional transmission
organization (RTO) concept, GridSouth implementation was suspended pending the
issuance and evaluation of new FERC directives. In July 2002 FERC issued a
Notice of Proposed Rulemaking (NOPR) on Standard Market Design 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. While it is anticipated that
significant change to the NOPR may occur and that implementation, presently
scheduled for September 2004, may not occur for some time, any rules
standardizing the markets may have 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. The Company is currently evaluating this NOPR to
determine what effect it will have on the Company's operations. Additional
directives from FERC are expected later in 2002.
The Company is not able to predict whether the preceding or similar
legislative or regulatory actions will be enacted and, if they are, the impact
they will have on the Company.
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.
On August 6, 2002 SCE&G filed an application with the Public Service
Commission of South Carolina (SCPSC) requesting a $104.7 million increase in
retail electric revenues. The electric rate request is largely associated with
the power generation projects recently completed at Urquhart Station and
the Jasper County Generating Station currently under construction, both of which
are discussed below. It also includes costs for equipment required for
environmental and air quality improvements.
The following table summarizes how SCE&G generated and used funds for
property additions and construction expenditures during the nine months ended
September 30, 2002 and 2001:
- -------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2002 2001
- ------------------------------------------------------------ ------------
Net cash provided from operating activities $215 $311
Net cash provided from (used for) financing
activities 157 (67)
Funds used for investments (7) (5)
Cash and temporary cash investments available
at the beginning of the period 78 60
- ---------------------------------------------------------------------------
Net cash available for utility property
additions and construction expenditures $443 $299
===========================================================================
Funds used for utility property additions and
construction expenditures, net of
noncash allowance for funds used
during construction $362 $263
===========================================================================
SCE&G anticipates that the remainder of its 2002 cash requirements will
be met through internally generated funds, the incurrence of additional
short-term and long-term indebtedness and a capital contribution from SCANA
Corporation. See Note 7A of Notes to Condensed Consolidated Financial
Statements. SCE&G expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the next 12 months and for
the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12
months ended September 30, 2002 was 3.55.
CAPITAL TRANSACTIONS
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem on
March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds, 8 7/8
percent Series due August 15, 2021.
On October 17, 2002 SCE&G received an equity contribution of $150
million from SCANA, which was used to pay off short-term debt primarily incurred
as a result of SCE&G's construction program.
On November 8, 2002 the South Carolina Jobs - Economic Development
Authority (JEDA) issued, and SCE&G received the proceeds of, an aggregate of
$90.4 million principal amount of Industrial Revenue Bonds Series 2002A and
2002B (the Bonds). The Bonds bear interest at rates ranging from 4.2 percent to
5.45 percent, with maturities ranging from 2012 to 2032. Proceeds from the Bonds
will be used to refund an aggregate amount of $62.3 million principal amount of
Pollution Control Revenue Bonds and to pay the costs of solid waste disposal
facilities at two of SCE&G's electric generating plants.
On November , 2002 SCH sold 275,000 ordinary shares of DTAG at a price of
$12.50 per share. The sale resulted in net after-tax proceeds of approximately $
million. In addition, SCH determined that the decline in value of its investment
in DTAG to below its cost basis of $ million (after-tax) in the fourth quarter
2002.
CAPITAL PROJECTS
SCE&G placed in service a $248 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 340 megawatts of new electric generation and use exhaust
heat to replace coal-fired steam that powers two existing 75 megawatt turbines
at the Urquhart Generating Station.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in
order to 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 $250 million and be completed in 2005.
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 the summer of 2004, and
SCG Pipeline, Inc., an affiliate, will transport natural gas to the facility. In
connection with the facility, SCE&G has signed an electric supply contract with
North Carolina Electric Membership Corporation to supply 350 megawatts in each
of 2004 and 2005 and 250 megawatts annually in 2006 through 2012.
SECURITIES RATINGS (As of September 30, 2002)
- -------------------------------------------------- ----------------------------
First and
First Refunding Trust
Rating Mortgage Mortgage Preferred Preferred Commercial
Agency Bonds Bonds Stock Securities Paper
Moody's A1 A1 Baa1 A3 P-1
Standard & Poor's A- A- BBB BBB A-1
Fitch Ratings A+ A+ A A F-1
- -------------------------------------------------- ----------------------------
The ratings above reflect Standard & Poor's one-notch downgrade in July
2002. SCE&G does not expect the downgrade to adversely impact SCE&G's liquidity.
Environmental Matters
For information on environmental matters see Note 5C of Notes To
Condensed Consolidated Financial Statements.
Other Matters
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over seven years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the historic Columbia Canal and Hydroelectric Plant to the
City. SCE&G will also pay the Central Midlands Regional Transit Authority up to
$3 million as matching funds for Federal Transit Administration grants for the
purchase of new transit coaches and a new transit facility.
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.
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002
AS COMPARED TO THE CORRESPONDING PERIOD IN 2001
Net Income
Net income for the third quarter and year to date periods ended
September 30, 2002 and 2001 was as follows:
- ------------------- ----------------------------------- ----------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ------------------- ---------- -------- --------------- ---------- --------- -------------------
Net income $86.2 $79.7 $6.5 8.2% $177.5 $176.2 $1.3 0.7%
- ------------------- ---------- -------- ------ -------- ---------- --------- --------- ---------
Third Quarter 2002 vs 2001
Net income increased primarily due to higher electric margins ($15.4
million), which were partially offset by higher operation and maintenance
expenses ($7.0 million) and higher property taxes ($1.5 million).
Year to Date 2002 vs 2001
Net income increased primarily due to higher electric margins ($18.6
million), which were partially offset by higher operation and maintenance
expenses ($17.5 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 in the third quarter and the year to date periods
of 2002 decreased significantly compared to corresponding periods in 2001
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:
- ------------------------------------------------------------ -----------------
Third Quarter Year to Date
Millions of dollars 2002 2001 2002 2001
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
Financial Statement Impact:
Reduction in employee benefit costs $1.3 $5.8 $7.8 $15.4
Increase in other income 4.5 3.6 8.4 9.7
Reduction in capital expenditures 0.4 1.7 2.3 4.4
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
Total Pension Income $6.2 $11.1 $18.5 $29.5
==============================================================================
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. Both the
equity and the debt portions of AFC are noncash items of nonoperating income
which have the effect of increasing reported net income. AFC represented
approximately six percent and nine percent of income before income taxes for the
three and nine months ended September 30, 2002, respectively, compared to
approximately five percent for both corresponding periods in 2001. The increase
in AFC for the nine months ended September 30, 2002 compared to the
corresponding period in 2001, is primarily the result of increased construction
expenditures related to the Urquhart Station repowering project, the Jasper
County Generating Station project and the Lake Murray Dam project (see
discussion at LIQUIDITY AND CAPITAL RESOURCES). AFC for the third quarter 2002
compared to the third quarter 2001 did not change significantly.
Dividends Declared
SCE&G's Board of Directors declared the following dividends on common
stock held by SCANA during 2002:
-------------------------------------- -------------------- ----------------
Declaration Date Dividend Amount Quarter Ended Payment Date
-------------------------------------- -------------------- ----------------
February 21, 2002 $34.0 million March 31, 2002 April 1, 2002
May 2, 2002 $38.0 million June 30, 2002 July 1, 2002
August 1, 2002 $40.5 million September 30, 2002 October 1, 2002
October 31, 2002 $40.5 million December 31, 2002 January 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:
--------------------------------------------------------------------- ------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
-------------------------------------- --------- -------------------- ---------- ---------- --------------------
Electric operating revenue $425.4 $417.6 $7.8 1.9% $1,079.3 $1,101.0 $(21.7) (2.0%)
Less: Fuel used in generation 85.9 69.1 16.8 24.3% 216.6 173.8 42.8 24.6%
Purchased power 35.7 69.6 (33.9) (48.7%) 110.8 205.5 (94.7) (46.1%)
------------------------------- --------- ---------- ---------- ---------
------- ---------
Margin $303.8 $278.9 $24.9 8.9% $751.9 $721.7 $30.2 4.2%
====================================== ========= ========= ========== ========== ========== ========= ==========
Third Quarter 2002 vs 2001
Margin increased due to more favorable weather ($14.7 million) and
customer growth ($12.8 million). Fuel used in generation increased and purchased
power decreased due to completion of the Urquhart Station repowering project in
June 2002.
Year to Date 2002 vs 2001
Margin increased due to more favorable weather ($14.7 million) and
customer growth ($19.3 million). Fuel used in generation increased and purchased
power decreased due to completion of the Urquhart Station repowering project in
June 2002 and more plants being on line during the period.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Changes in the gas distribution sales margins were as follows:
----------------------------------- ------------------------------------- ------------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
----------------------------------- ------- --------- ------------------- --------- --------- ----------------------
Gas operating revenue $47.1 $43.0 $4.1 9.5% $207.2 $257.9 $(50.7) (19.7%)
Less: Gas purchased for resale 36.0 32.6 3.4 10.4% 148.2 198.0 (49.8) (25.2%)
----------------------------------- -------- --------- --------- -----------
------- ---------
Margin $11.1 $10.4 $0.7 6.7% $59.0 $59.9 $(0.9) (1.5%)
=================================== ======= ========= ======== ========== ========= ========= =========== ==========
Third Quarter 2002 vs 2001
Margin increased primarily due to an improved competitive position
relative to alternate fuels for interruptible customers.
Year to Date 2002 vs 2001
Margins decreased primarily due to milder weather and weak economic
conditions in the first quarter ($3.8 million), which were partially offset by
customer growth ($1.6 million) and an improved competitive position relative to
alternate fuels for interruptible customers ($1.9 million). Revenues and gas
purchases decreased as a result of lower commodity natural gas prices in the
first and second quarters.
Other Operating Expenses
Changes in other operating expenses were as follows:
- ----------------------------------------------------------------------- ----------------------------------------
Third Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ------------------------------------------ --------- ------------------ --------- --------- --------------------
Other operation and maintenance $89.7 $78.4 $11.3 14.4% $269.2 $240.9 $28.3 11.7%
Depreciation and amortization 42.6 40.9 1.7 4.2% 126.6 122.5 4.1 3.3%
Other taxes 27.3 24.8 2.5 10.1% 81.6 75.2 6.4 8.5%
- ---------------------------------- ------- --------- --------- ---------
-------- ---------
Total $159.6 $144.1 $15.5 $10.8% $477.4 $438.6 $38.8 8.8%
========================================== ========= ======= ========== ========= ========= ========= ==========
Third Quarter 2002 vs 2001
Other operation and maintenance expenses increased primarily due to
reduced pension income ($4.5 million) and increased labor and benefits costs
($3.9 million). Depreciation and amortization expense increased primarily due to
completion of the Urquhart Station repowering project in June 2002. Other taxes
increased primarily due to increased property taxes.
Year to Date 2002 vs 2001
Other operation and maintenance expenses increased primarily due to
reduced pension income ($7.6 million), increased labor and benefit costs ($8.2
million), increased nuclear refueling maintenance costs ($4.0 million),
increased costs at Cope Generating Station and Cogen South ($3.6 million) and
higher property insurance costs ($2.8 million). Depreciation and amortization
expense increased primarily due to completion of the Urquhart Station repowering
project in June 2002 ($3.2 million) and normal net property additions ($0.9
million). Other taxes increased primarily due to increased property taxes.
Other Income
Third Quarter and Year to Date 2002 vs 2001
Other income, including AFC, increased primarily due to construction at
Urquhart Station (completed in June 2002), the Jasper County Generation Station
project and Lake Murray Dam.
Interest Expense
Third Quarter and Year to Date 2002 vs 2001
Interest expense increased primarily due to increased long-term debt ($9.4
million), and was partially offset by declining interest rates ($0.7 million).
Income Taxes
Third Quarter and Year to Date 2002 vs 2001
Income taxes changed primarily as a result of changes in operating income.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates.
As of September 30, 2002
Millions of dollars Expected Maturity Date
There- Fair
Liabilities 2002 2003 2004 2005 2006 after Total Value
- ------------------------------- -------- -------- -------- --------- ---------------------- ------------
- ------------------------------- -------- -------- -------- --------- ---------------------- ------------
Long-Term Debt:
Fixed Rate ($) 16.5 129.5 123.9 173.9 154.6 1,147.8 1,746.2 1,731.5
Average Interest Rate 1.89 6.33 7.52 7.40 8.66 6.91 7.07
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 September 30, 2002, an evaluation was performed under the
supervision and with the participation of SCE&G's management, including the CEO
and 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 SCE&G's disclosure controls and procedures were
effective as of September 30, 2002. There have been no significant changes in
SCE&G's internal controls or in other factors that could significantly affect
internal controls subsequent to September 30, 2002.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
--------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ------------------------------------------------------------------------- -------------------
September 30, December 31,
Millions of dollars 2002 2001
- ------------------------------------------------------------------------- -------------------
Assets
Gas Utility Plant $885 $855
Accumulated depreciation (310) (288)
Acquisition adjustment, net of accumulated amortization 439 439
- ------------------------------------------------------------------------- -------------------
Gas Utility Plant, Net 1,014 1,006
- ------------------------------------------------------------------------- -------------------
Nonutility Property and Investments, Net 29 29
- ------------------------------------------------------------------------- -------------------
Current Assets:
Cash and temporary investments 4 18
Restricted cash and temporary investments 2 2
Receivables (net of allowance for
uncollectible accounts of $1 and $1) 28 70
Receivables - affiliated companies 11 12
Inventories (at average cost):
Stored gas 43 47
Materials and supplies 8 8
Deferred income taxes, net 3 -
- ------------------------------------------------------------------------- -------------------
Total Current Assets 99 157
- ------------------------------------------------------------------------- -------------------
Deferred Debits:
Due from affiliate-pension asset 14 14
Regulatory assets 21 11
Other 9 4
- ------------------------------------------------------------------------- -------------------
Total Deferred Debits 44 29
- ------------------------------------------------------------------------- -------------------
Total $1,186 $1,221
========================================================================= ===================
========================================================================= ===================
Capitalization and Liabilities
Capitalization:
Common equity $713 $715
Long-term debt, net 291 290
- ------------------------------------------------------------------------- -------------------
Total Capitalization 1,004 1,005
- ------------------------------------------------------------------------- -------------------
Current Liabilities:
Current portion of long-term debt 8 4
Accounts payable 16 41
Accounts payable -affiliated companies 6 10
Customer prepayments and deposits 18 17
Taxes accrued 4 5
Dividends declared and interest accrued 9 6
Other 2 3
- ------------------------------------------------------------------------- -------------------
Total Current Liabilities 63 86
- ------------------------------------------------------------------------- -------------------
Deferred Credits:
Deferred income taxes, net 87 86
Deferred investment tax credits 2 2
Due to affiliate-postretirement benefits 16 14
Regulatory liabilities - 14
Other 14 14
- ------------------------------------------------------------------------- -------------------
Total Deferred Credits 119 130
- ------------------------------------------------------------------------- -------------------
Total $1,186 $1,221
========================================================================= ===================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars 2002 2001 2002 2001
--------------------------------------------------------------------- -------------- --------------- --------------
Operating Revenues $39 $47 $222 $343
Cost of Gas 18 25 107 228
--------------------------------------------------------------------- -------------- --------------- --------------
Gross Margin 21 22 115 115
--------------------------------------------------------------------- -------------- --------------- --------------
Operating Expenses:
Operation and maintenance 16 19 50 51
Depreciation and amortization 9 10 26 32
Other taxes 2 2 5 5
--------------------------------------------------------------------- -------------- --------------- --------------
Total Operating Expenses 27 31 81 88
--------------------------------------------------------------------- -------------- --------------- --------------
Operating Income (Loss) (6) (9) 34 27
--------------------------------------------------------------------- -------------- --------------- --------------
--------------------------------------------------------------------- -------------- --------------- --------------
Other Income, including allowance for equity funds
used during construction of $0, $0, $1 and $0 1 1 3 5
Interest Charges, net of allowance for borrowed funds
used during construction of $0, $0, $0 and $1 5 6 17 16
--------------------------------------------------------------------- -------------- --------------- --------------
Income (Loss) Before Income Taxes (10) (14) 20 16
Income Tax Expense (Benefit) (4) (4) 7 10
--------------------------------------------------------------------- -------------- --------------- --------------
--------------------------------------------------------------------- -------------- --------------- --------------
Net Income (Loss) $(6) $(10) $13 $6
===================================================================== ============== =============== ==============
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- ------------------------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2002 2001
- ----------------------------------------------------------------------------- ------------
Cash Flows From Operating Activities:
Net income $13 $6
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 28 34
Allowance for funds used during construction (1) (1)
Excess distributions of equity method investee - 3
Over (under) collection, fuel adjustment clause (26) 14
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 43 99
(Increase) decrease in inventories 4 (16)
(Increase) decrease in regulatory assets 1 1
Increase (decrease) in accounts payable and advances (29) (101)
Increase (decrease) in deferred income taxes, net (2) 3
Increase (decrease) in accrued taxes (1) (2)
Changes in other assets (1) 2
Changes in other liabilities - (2)
- ----------------------------------------------------------------------------- ------------
Net Cash Provided From Operating Activities 29 40
- ----------------------------------------------------------------------------- ------------
Cash Flows From Investing Activities:
Construction expenditures (34) (40)
Nonutility and other (1) 1
- ----------------------------------------------------------------------------- ------------
Net Cash Used For Investing Activities (35) (39)
- ----------------------------------------------------------------------------- ------------
Cash Flows From Financing Activities:
Issuance of medium-term notes - 148
Repayment of short-term borrowings, net - (125)
Capital contributions from parent 1 4
Cash dividends (9) (15)
- ----------------------------------------------------------------------------- ------------
Net Cash Provided From (Used For) Financing Activities (8) 12
- ----------------------------------------------------------------------------- ------------
Net Increase (Decrease) In Cash and Temporary Investments (14) 13
Cash and Temporary Investments, January 1 18 8
- ----------------------------------------------------------------------------- ------------
Cash and Temporary Investments, September 30 $4 $21
============================================================================= ============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $0.7 and $0.8) $16 $12
- Income taxes 13 15
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2002
(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, 2001. 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 September 30, 2002 approximately $21 million and $0.3 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax liabilities of approximately $0.3 million. The North
Carolina Utilities Commission (NCUC) has reviewed and approved most of the items
shown as regulatory assets through specific orders. Other items represent costs
which are not yet approved for recovery by the NCUC, but are the subject of
current or future filings. In recording these costs as regulatory assets,
management believes the costs will be allowable under existing rate-making
concepts that are embodied in current rate orders received by the Company. 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 141, "Business Combinations," and SFAS 142,
"Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141
requires all acquisitions to be accounted for utilizing the purchase method. The
Company considers the amounts categorized by the Federal Energy Regulatory
Commission (FERC) as "acquisition adjustments" to be goodwill as defined in SFAS
142 and ceased amortization of such amounts upon the adoption of SFAS 142. This
amortization is related to the acquisition adjustment of approximately $466
million carried on the books of the Company. The Company has no other intangible
assets subject to amortization as provided in SFAS 142.
If the Company had ceased amortization during all periods presented in
the condensed consolidated statements of operations, net income (loss) would
have been as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
(Millions of dollars) 2002 2001 2002 2001
---- ---- ---- ----
Net Income (Loss) as Reported $(6) $(10) $13 $6
Amortization of Acquisition Adjustment - 3 - 10
--- ---- ---- ----
Net Income (Loss) as Adjusted $(6) $(7) $13 $16
==== ==== === ===
SFAS 142 provides a six-month transitional period from the effective
date of adoption for the Company to perform an assessment of whether there is an
indication that goodwill is impaired. The Company's initial analysis indicated
that a write-down of the acquisition adjustment associated with PSNC ranging
from $200 million to $250 million will be required. The final valuation analysis
will be completed by December 31, 2002, and any write-down resulting from the
analysis will be recorded as the cumulative effect of a change in accounting
principle.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing liabilities related to the future
obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective
January 1, 2003. The impact SFAS 143 may have on the Company's financial
position has not been determined but could be material. Because any ARO
anticipated to be recorded would relate to regulated operations, it is not
expected that the initial adoption of the statement will have any impact on
results of operations or cash flows.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," became effective January 1, 2002. This statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements for the initial
adoption of SFAS 144.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The
provisions of SFAS 145, among other things, discontinue treating gains or losses
from the early extinguishment of debt as extraordinary items unless such early
extinguishment meets the criteria of Accounting Principles Board Opinion No. 30.
The Company will adopt SFAS 145 effective January 1, 2003 and does not expect
that such initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. 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.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that such initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
The Company's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. The Company revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the 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, 2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2002
$.750 February-March 2001 $.215 February-June 2002
$.650 April-August 2001 $.350 July-September 2002
$.500 September-October 2001
$.350 November-December 2001
On October 28, 2002 the NCUC approved the Company's request to increase
the benchmark cost of gas from $.350 per therm to $.410 per therm effective for
service rendered on and after November 1, 2002.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from the Company's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. 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 portion of the
project was completed in 2001. The Jackson County portion of the project should
be complete by the end of 2002. At September 30, 2002 approximately $14.5
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 NCUC order, the Company reduced its rates by
approximately $1 million in each of August 2000 and August 2001, and agreed to a
moratorium on general rate cases until August 2005. General rate relief can be
obtained during this period to recover costs associated with material adverse
governmental actions and force majeure events.
3. FINANCIAL INSTRUMENTS
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended. SFAS 133
requires the Company to recognize all derivative instruments as either assets or
liabilities in the statement of financial position and to measure those
instruments at fair value. SFAS 133 further provides that changes in fair value
of derivative instruments are either recognized in earnings or reported as other
comprehensive income, depending upon the intended use of the derivative and the
resulting designation. The impact on the Company of adopting SFAS 133 was not
material.
In December 2001 the Company entered into two interest rate swap
agreements to pay variable rates and receive fixed rate interest payments on a
combined notional amount of $44.9 million. These swaps were designated as fair
value hedges of the Company's $12.9 million, 10% senior debenture due 2004 and
$32.0 million, 8.75% senior debenture due 2012. At September 30, 2002 the fair
value of these swaps was $3.3 million.
The fair value of these 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 on the balance sheet. The receipts or payments
related to the interest rate swaps are credited or charged to interest expense
as incurred.
4. COMMITMENTS AND CONTINGENCIES
The Company owns, or has owned, all or portions of seven sites in North
Carolina on which manufactured gas plants (MGPs) were formerly operated.
Intrusive investigation (including drilling, sampling and analysis) has begun at
two sites, and the remaining sites have been evaluated using historical records
and observations of current site conditions. These evaluations have revealed
that MGP residuals are present or suspected at several of the sites. The
Company's associated actual costs for these sites will depend on a number of
factors, such as actual site conditions, third-party claims and recoveries from
other potentially responsible parties (PRPs). In September 2002 an allocation
agreement was reached relieving PSNC of liability for two of the seven sites.
The Company has recorded a liability and associated regulatory asset of $8.0
million, which reflects its estimated remaining liability at September 30, 2002.
Amounts incurred to date that have not been recovered through gas rates are
approximately $1.1 million. Management believes that all MGP cleanup costs will
be recoverable through gas rates.
5. SEGMENT OF BUSINESS INFORMATION
Gas Distribution is the Company's only reportable segment. Gas
Distribution uses operating income to measure profitability. Intersegment
revenues between Gas Distribution and nonreportable segments were not
significant.
Disclosure of Reportable Segments
(Millions of Dollars)
- ------------------------------------- ---------------- --------------------
Three months ended External Operating
September 30, 2002 Revenue Income
- ------------------------------------- ---------------- --------------------
Gas Distribution $39 $(6)
All Other - n/a
Adjustments/Eliminations - -
- ------------------------------------- ---------------- --------------------
- ------------------------------------- ---------------- --------------------
Consolidated Total $39 $(6)
===================================== ================ ====================
------------------------------------- ---------------- --------------------
Three months ended External Operating
September 30, 2001 Revenue Loss
------------------------------------- ---------------- --------------------
Gas Distribution $47 $(9)
All Other - n/a
Adjustments/Eliminations - -
------------------------------------- ---------------- --------------------
------------------------------------- ---------------- --------------------
Consolidated Total $47 $(9)
===================================== ================ ====================
- ------------------------------------------- ------------------- ---------------
Nine months ended External Operating Segment
September 30, 2002 Revenue Income Assets
- ------------------------------------------- ------------------- ---------------
Gas Distribution $222 $34 $1,155
All Other - n/a 29
Adjustments/Eliminations - - 2
- ------------------------------------------- ------------------- ---------------
Consolidated Total $222 $34 $1,186
=========================================== =================== ===============
- ------------------------------------------- ------------------- ---------------
Nine months ended External Operating Segment
September 30, 2001 Revenue Income Assets
- ------------------------------------------- ------------------- ---------------
Gas Distribution $343 $27 $1,148
All Other - n/a 28
Adjustments/Eliminations - - (14)
- ------------------------------------------- ------------------- ---------------
Consolidated Total $343 $27 $1,162
=========================================== =================== ===============
60
Item 2. Management's Narrative Analysis of Results of Operations.
---------------------------------------------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Narrative Analysis of Results of Operations appearing in Public Service Company
of North Carolina, Incorporated's (PSNC) Annual Report on Form 10-K for the year
ended December 31, 2001.
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's service territory,
(4) the impact of competition from other energy suppliers, (5) growth
opportunities, (6) the results of financing efforts, (7) changes in PSNC's
accounting policies, (8) weather conditions, especially in areas served by PSNC,
(9) performance of SCANA Corporation's pension plan assets and the impact on
PSNC'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's periodic reports filed with the SEC. PSNC disclaims any
obligation to update any forward-looking statements.
Net Income and Dividends
Net income for the nine months ended September 30, 2002 and 2001 was as
follows:
Millions of dollars 2002 2001
- ------------------------------------ --------------- --------------
Net income $13.1 $5.7
==================================== =============== ==============
Net income increased primarily due to the elimination of the
amortization of the acquisition adjustment ($10.0 million-see Note 1B of Notes
to Condensed Consolidated Financial Statements), which was partially offset by
reduced other income ($2.1 million).
The nature of PSNC's business is seasonal. The quarters ending June 30
and September 30 are generally PSNC's least profitable quarters due to decreased
demand for natural gas related to lower space heating requirements.
PSNC's Board of Directors authorized payment of dividends on common
stock held by SCANA as follows:
- --------------------- ----------------- --------------------- -----------------
Declaration Date Dividend Amount Quarter Ended Payment Date
- --------------------- ----------------- --------------------- -----------------
- --------------------- ----------------- --------------------- -----------------
February 21, 2002 $5.0 million March 31, 2002 April 1, 2002
May 2, 2002 $4.0 million June 30, 2002 July 1, 2002
August 1, 2002 $5.5 million September 30, 2002 October 1, 2002
October 31, 2002 $5.5 million December 31, 2002 January 1, 2003
- --------------------- ----------------- --------------------- -----------------
Gas Distribution
Gas distribution is comprised of the local distribution operations of
PSNC. Changes in the gas distribution sales margins for the nine months ended
September 30, 2002 compared to the same period in 2001 were as follows:
Millions of dollars 2002 2001 Change % Change
- --------------------------------------------------------------------------------
Operating revenues $222.0 $342.9 $(120.9) (35.26%)
Less: Cost of gas 106.7 227.8 (121.1) (53.16%)
- -----------------------------------------------------------
Gross margin $115.3 $115.1 $0.2 0.17%
================================================================================
Gas distribution sales margin for the nine months ended September 30,
2002 increased primarily due to increased residential customer growth. The
increase in margin was partially offset by the effects of a $1 million reduction
in rates in August 2001 related to the acquisition of PSNC by SCANA. Revenues
and cost of gas decreased as a result of lower commodity natural gas prices in
the first and second quarters.
Operation and Maintenance Expenses
Operation and maintenance expenses decreased $0.9 million for the nine
months ended September 30, 2002 compared to the same period in 2001. The
decrease was primarily due to lower bad debt expense ($2.6 million), which was
partially offset primarily by increased costs for customer billing and
collections ($2.2 million).
Depreciation and Amortization Expense
Depreciation and amortization expenses decreased primarily due to
implementation of SFAS 142 and the resulting elimination of amortization expense
related to goodwill ($10.0 million-see Note 1B of Notes to Condensed
Consolidated Financial Statements), which was partially offset by increases for
normal property additions ($3.8 million).
Other Income
Other income decreased $2.1 million for the nine months ended September
30, 2002 compared to the same period in 2001. The decrease was primarily due to
reduced interest income ($1.2 million) and an increased provision for bad debt
for merchandise and jobbing ($0.4 million).
Capital Expansion Program and Liquidity Matters
PSNC's capital expansion program includes the construction of lines,
systems and facilities and the purchase of related equipment. PSNC's 2002
construction budget is approximately $41 million, compared to actual
construction expenditures for 2001 of $75.3 million. PSNC's ratio of earnings to
fixed charges for the 12 months ended September 30, 2002 was 2.6.
In December 2001 PSNC entered into two interest rate swap agreements to
pay variable rates and receive fixed rates on a combined notional amount of
$44.9 million. (See Note 3 of Notes to Condensed Consolidated Financial
Statements.)
SECURITIES RATINGS (As of September 30, 2002)
PSNC
- ------------------------------------------------------
Rating Senior Commercial
Agency Unsecured Paper
Moody's A2 P-1
Standard & Poor's A- A-1
Fitch Ratings n/a n/a
- --------------------- -------------- -----------------
The ratings above reflect Standard & Poor's one-notch downgrade in July
2002. The Company does not expect the downgrade to adversely impact the
Company's liquidity.
Item 4. Controls and Procedures
As of September 30, 2002, an evaluation was performed under the
supervision and with the participation of PSNC's management, including the CEO
and CFO, of the effectiveness of the design and operation of PSNC's disclosure
controls and procedures. Based on that evaluation, PSNC's management, including
the CEO and CFO, concluded that PSNC's disclosure controls and procedures were
effective as of September 30, 2002. There have been no significant changes in
PSNC's internal controls or in other factors that could significantly affect
internal controls subsequent to September 30, 2002.
81
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
SCANA Corporation:
For information regarding legal proceedings see Notes 4 and 13 of Notes
To Consolidated Financial Statements appearing in the Company's Annual Report on
Form 10-K for the year ended December 31, 2001. Additional information is as
follows:
RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company (SCE&G)
Electric
On August 6, 2002 SCE&G filed an application with the SCPSC requesting a
$104.7 million increase in retail electric revenues. The electric rate request
is largely associated with the power generation projects recently completed at
Urquhart Station and the Jasper County Generating Station currently under
construction. It also includes costs for equipment required for environmental
and air quality improvements. Hearings on this request are to be held in late
November 2002, with an order expected in February 2003.
In April 2002 the SCPSC approved SCE&G's request to increase the fuel
component of rates charged to electric customers from 1.579 cents per
kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2002 through April 2003. The increase
also provides recovery for under-collected actual fuel costs through April 2002,
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.
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,
2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-September 2002
On October 22, 2002, as part of the annual review of gas costs, the
SCPSC approved SCE&G's request to increase the cost of gas component from $.596
per therm to $.728 per therm effective with the first billing cycle in November
2002.
In 1994 the SCPSC issued an order approving SCE&G's request to recover,
through a billing surcharge to its gas customers, the costs of environmental
cleanup at the sites of former manufactured gas plants (MGPs). The billing
surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for SCE&G's gas operations that had previously
been deferred. In October 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 of the balance remaining at September 30, 2002
($19.7 million) prior to the end of 2005.
Public Service Company of North Carolina, Incorporated (PSNC)
PSNC'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 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's gas purchasing practices annually.
PSNC's benchmark cost of gas in effect during the period January 1,
2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2002
$.750 February-March 2001 $.215 February-June 2002
$.650 April-August 2001 $.350 July-September 2002
$.500 September-October 2001
$.350 November-December 2001
On October 28, 2002 the NCUC approved PSNC's request to increase the
benchmark cost of gas from $.350 per therm to $.410 per therm effective for
service rendered on and after November 1, 2002.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund to
extend natural gas service to Madison, Jackson and Swain Counties in western
North Carolina. PSNC estimates that the cost of this project will be
approximately $31.4 million. The Madison County portion of the project was
completed in 2001. The Jackson County portion of the project should be complete
by the end of 2002. At September 30, 2002, approximately $14.5 million had been
spent on this project.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately
$1 million in each of August 2000 and August 2001, and agreed to a moratorium on
general rate cases until August 2005. General rate relief can be obtained during
this period to recover costs associated with material adverse governmental
actions and force majeure events.
South Carolina Pipeline Corporation (SCPC)
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In an order dated August 15, 2002
the SCPSC found that for the period January 2001 through March 2002 SCPC's gas
purchasing policies and practices were prudent and the gas cost recovery
provisions of its gas tariff were properly adhered to.
COMMITMENTS AND CONTINGENCIES
Commitments and contingencies at September 30, 2002 include the
following:
Lake Murray Dam Reinforcement
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam
in order to 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 $250 million and be completed in 2005.
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.
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.
Environmental
South Carolina Electric & Gas Company
In September 1992 the Environmental Protection Agency (EPA) notified
SCE&G, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of SCE&G's decommissioned MGPs.
Field work at the site began in November 1993 and has required the submission of
several investigative reports and the implementation of several work plans. In
September 2000, SCE&G was notified by the South Carolina Department of Health
and Environmental Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park area site.
The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility
Study on the intermediate aquifer, which was completed in June 2001. The EPA
issued a Record of Decision dealing with the intermediate aquifer and sediments
in October 2002. The Record of Decision affirmed SCE&G's proposed remediation
approach. A Remedial Design Work Plan will be prepared by SCE&G by early 2003
for agency input and concurrence. SCE&G anticipates that the remaining
remediation activities will be implemented in 2003, with certain monitoring and
retreatment activities continuing until 2007. As of September 30, 2002, SCE&G
has spent approximately $18.8 million to remediate the Calhoun Park area 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 $2.1
million related to these sites and expects to spend an additional $5.9 million.
Public Service Company of North Carolina, Incorporated
PSNC owns, or has owned, all or portions of seven sites in North
Carolina on which MGPs were formerly operated. Intrusive investigation
(including drilling, sampling and analysis) has begun at two sites and the
remaining sites have been evaluated using historical records and observations of
current site conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. PSNC's associated actual costs for
these sites will depend on a number of factors, such as actual site conditions,
third-party claims and recoveries from other potentially responsible parties
(PRPs). In September 2002 an allocation agreement was reached relieving PSNC of
liability for two of the seven sites. PSNC has recorded a liability and
associated regulatory asset of $8.0 million, which reflects the estimated
remaining liability at September 30, 2002. Amounts incurred to date that have
not been recovered through gas
rates are approximately $1.1 million. Management believes that all MGP cleanup
costs will be recoverable through gas rates.
South Carolina Electric & Gas Company:
For information regarding legal proceedings see Notes 3 and 12 of Notes
To Consolidated Financial Statements appearing in South Carolina Electric & Gas
Company's Annual Report on Form 10-K for the year ended December 31, 2001.
Additional information is as follows:
RATE AND OTHER REGULATORY MATTERS
Electric
On August 6, 2002 SCE&G filed an application with the SCPSC requesting a
$104.7 million increase in retail electric revenues. The electric rate request
is largely associated with the power generation projects recently completed at
Urquhart Station and the Jasper County Generating Station currently under
construction. It also includes costs for equipment required for environmental
and air quality improvements. Hearings on this request are to be held in late
November 2002, with an order expected in February 2003.
In April 2002 the SCPSC approved SCE&G's request to increase
the fuel component of rates charged to electric customers from 1.579 cents per
kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2002 through April 2003. The increase
also provides recovery for under-collected actual fuel costs through April 2002,
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.
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 the Company.
SCE&G's cost of gas component in effect during the period January 1,
2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-September 2002
On October 22, 2002, as part of the annual review of gas costs, the
SCPSC approved SCE&G's request to increase the cost of gas component from $.596
per therm to $.728 per therm effective with the first billing cycle in November
2002.
In 1994 the SCPSC issued an order approving SCE&G's request to recover,
through a billing surcharge to its gas customers, the costs of environmental
cleanup at the sites of former manufactured gas plants (MGPs). The billing
surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for SCE&G's gas operations that had previously
been deferred. In October 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 of the balance remaining at September 30, 2002
($20.6 million) prior to the end of 2005.
COMMITMENTS AND CONTINGENCIES
Commitments and Contingencies at September 30, 2002 include the
following:
Lake Murray Dam Reinforcement
In October 1999 the Federal Energy Regulatory Commission (FERC) mandated
that the Company reinforce its Lake Murray dam in order to 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 $250 million and be completed in 2005.
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 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.
Environmental
In September 1992 the Environmental Protection Agency (EPA) notified
SCE&G, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of SCE&G's decommissioned MGPs.
Field work at the site began in November 1993 and has required the submission of
several investigative reports and the implementation of several work plans. In
September 2000, SCE&G was notified by the South Carolina Department of Health
and Environmental Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park area site.
The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility
Study on the intermediate aquifer, which was completed in June 2001. The EPA
issued a Record of Decision dealing with the intermediate aquifer and sediments
in October 2002. The Record of Decision affirmed SCE&G's proposed remediation
approach. A Remedial Design Work Plan will be prepared by SCE&G by early 2003
for agency input and concurrence. SCE&G anticipates that the remaining
remediation activities will be implemented in 2003, with certain monitoring and
retreatment activities continuing until 2007. As of September 30, 2002, SCE&G
has spent approximately $18.8 million to remediate the Calhoun Park area 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 $2.1 million related to these sites and expects to spend an
additional $5.9 million.
Public Service Company of North Carolina, Incorporated:
For information regarding legal proceedings see Notes 5 and 11 of Notes
To Consolidated Financial Statements appearing in Public Service Company of
North Carolina, Incorporated's Annual Report on Form 10-K for the year ended
December 31, 2001. Additional information is as follows:
RATE AND OTHER REGULATORY MATTERS
PSNC'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 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's gas purchasing practices annually.
PSNC's benchmark cost of gas in effect during the period January 1,
2001 through September 30, 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2002
$.750 February-March 2001 $.215 February-June 2002
$.650 April-August 2001 $.350 July-September 2002
$.500 September-October 2001
$.350 November-December 2001
On October 28, 2002 the NCUC approved PSNC's request to increase the
benchmark cost of gas from $.350 per therm to $.410 per therm effective for
service rendered on and after November 1, 2002.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund to
extend natural gas service to Madison, Jackson and Swain Counties in western
North Carolina. PSNC estimates that the cost of this project will be
approximately $31.4 million. The Madison County portion of the project was
completed in 2001. The Jackson County portion of the project should be complete
by the end of 2002. At September 30, 2002 approximately $14.5 million had been
spent on this project.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately
$1 million in each of August 2000 and August 2001, and 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.
COMMITMENTS AND CONTINGENCIES
PSNC owns, or has owned, all or portions of seven sites in North
Carolina on which MGPs were formerly operated. Intrusive investigation
(including drilling, sampling and analysis) has begun at two sites and the
remaining sites have been evaluated using historical records and observations of
current site conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. PSNC's associated actual costs for
these sites will depend on a number of factors, such as actual site conditions,
third-party claims and recoveries from other potentially responsible parties
(PRPs). In September 2002 an allocation agreement was reached relieving PSNC of
liability for two of the seven sites. PSNC has recorded a liability and
associated regulatory asset of $8.0 million, which reflects the estimated
remaining liability at September 30, 2002. Amounts incurred to date that have
not been recovered through gas rates are approximately $1.1 million. Management
believes that all MGP cleanup costs will be recoverable through gas rates.
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.
As permitted under Item 601(b)(4)(iv), instruments defining the
rights of holders of long-term debt of less than 10 percent of
the total consolidated assets of SCANA, for itself and its
subsidiaries, of SCE&G, for itself and its subsidiaries, and of
PSNC, for itself and its subsidiaries, have been omitted and
SCANA, SCE&G and PSNC agree to furnish a copy of such instruments
to the Commission upon request.
B. Reports on Form 8-K during the third quarter of 2002 were as
follows:
SCANA Corporation:
Date of report: July 26, 2002
Item reported: Item 5
Date of report: August 13, 2002
Items reported: Items 7 and 9
South Carolina Electric & Gas Company: None
Public Service Company of North Carolina, Incorporated: None
SCANA CORPORATION
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SCANA CORPORATION
(Registrant)
November 12, 2002 By: s/James E. Swan, IV
---------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
(Registrant)
November 12, 2002 By: s/James E. Swan, IV
------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
(Registrant)
November 12, 2002 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: November 12, 2002
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive Officer,
President 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: November 12, 2002
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: November 12, 2002
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: November 12, 2002
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: November 12, 2002
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: November 12, 2002
s/Kevin B. Marsh
Kevin B. Marsh
President and Chief Financial
Officer
EXHIBIT INDEX
Exhibit Applicable to
Form 10-Q of
No. SCANA SCE&G PSNC Description
2.01 X X Agreement and Plan of Merger, dated as of February
16, 1999 as amended and restated as of May 10, 1999,
by and among Public Service Company of North
Carolina, Incorporated, SCANA Corporation, New Sub
I, Inc. and New Sub II, Inc.(Filed as Exhibit 2.1 to
Registration Statement No. 333-78227 on Form S-4)
3.01 X Restated Articles of Incorporation of SCANA as
adopted on April 26, 1989 (Filed as Exhibit 3-A to
Registration Statement No. 33-49145)
3.02 X Articles of Amendment of SCANA, dated April 27, 1995
(Filed as Exhibit 4-B to Registration Statement No.
33-62421)
3.03 X Restated Articles of Incorporation of SCE&G, as
adopted on May 3, 2001 (Filed as Exhibit 3.01 to
Registration Statement No. 333-65460)
3.04 X Articles of Amendment of SCE&G dated May 22, 2001
(Filed as Exhibit 3.02 to Registration Statement No.
333-65460)
3.05 X Articles of Correction of SCE&G dated June 1, 2001
(Filed as Exhibit 3.03 to Registration Statement No.
333-65460)
3.06 X Articles of Amendment of SCE&G dated June 14, 2001
(Filed as Exhibit 3.04 to Registration Statement No.
333-65460)
3.07 X Articles of Amendment of SCE&G dated August 30, 2001
(Filed as Exhibit 3.07 to Form 10-Q for the quarter
ended June 30, 2002)
3.08 X Articles of Amendment of SCE&G dated March 13, 2002
(Filed as Exhibit 3.08 to
Form 10-Q for the quarter ended June 30, 2002)
3.09 X Articles of Amendment of SCE&G dated May 9, 2002
(Filed as Exhibit 3.09 to Form
10-Q for the quarter ended June 30, 2002)
3.10 X Articles of Amendment of SCE&G, dated June 4, 2002
(Filed herewith)
3.11 X Articles of Amendment of SCE&G, dated August 12,
2002 (Filed herewith)
EXHIBIT INDEX
Exhibit Applicable to
Form 10-Q of
No. SCANA SCE&G PSNC Description
3.12 X Articles of Incorporation of PSNC (formerly New Sub
II, Inc.) dated February 12, 1999 (Filed as Exhibit
3.01 to Registration Statement No. 333-45206)
3.13 X Articles of Amendment of PSNC (formerly New Sub II,
Inc.) as adopted on February 10, 2001 (Filed as
Exhibit 3.02 to Registration Statement No.333-45206)
3.14 X Articles of Correction of PSNC dated February 11,
2001 (Filed as Exhibit 3.03 to Registration
Statement No. 333-45206)
3.15 X By-Laws of SCANA as revised and amended on December
13, 2001 (Filed as Exhibit 3.01 to Registration
Statement No. 333-68266)
3.16 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)
3.17 X By-Laws of PSNC (formerly New Sub II, Inc.) as
revised and amended on February 22, 2001 (Filed as
Exhibit 3.01 to Registration Statement No.
333-68516)
4.01 X Articles of Exchange of South Carolina Electric
and Gas Company and SCANA Corporation (Filed as
Exhibit 4-A to Post-Effective Amendment
No. 1 to Registration Statement No. 2-90438)
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
EXHIBIT INDEX
Exhibit Applicable to
Form 10-Q of
No. SCANA SCE&G PSNC Description
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-O to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 2-B to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 2-A-3 to Registration No. 33-38580
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
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)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
4.11 X X Junior Subordinated Indenture for SCE&G Trust I
(Filed as Exhibit 4.05 to Registration
Statement No. 333-49960)
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as
Exhibit 4.06 to Registration Statement No.
333-49960)
4.13 X X Amended and Restated Trust Agreement for SCE&G
Trust I (Filed as Exhibit 4.07
to Registration Statement No. 333-49960)
4.14 X X Indenture dated as of January 1, 1996 between
PSNC and First Union National
Bank of North Carolina, as Trustee (Filed as
Exhibit 4.08 to Registration
Statement No. 333-45206)
4.15 X X First Supplemental Indenture dated as of
January 1, 1996, between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit 4.09
to Registration Statement No. 333-45206)
4.16 X X Second Supplemental Indenture dated as of
December 15, 1996 between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit 4.10
to Registration Statement No. 333-45206)
4.17 X X Third Supplemental Indenture dated as of
February 10, 2001 between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit 4.11
to Registration Statement No. 333-45206)
4.18 X X Fourth Supplemental Indenture dated as of
February 12, 2001 between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit 4.05 to
Registration Statement No. 333-68516)
4.19 X PSNC $150 million medium-term note issued
February 16, 2001 (Filed as Exhibit 4.06 to
Registration Statement No. 333-68516)
10.01 X SCANA Executive Deferred Compensation Plan as
amended July 1, 2001 (Filed 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)
10.03a 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)
10.04 X SCANA Performance Share Plan as
amended and restated effective
January 1, 1998 (Filed as Exhibit 10
(e) to Registration Statement No.
333-86803)
10.05 X SCANA Long-Term Equity Compensation
Plan dated January 2001 filed as
Exhibit 4.04 to Registration
Statement No. 333-37398)
EXHIBIT INDEX
Exhibit Applicable to
Form 10-Q of
No. SCANA SCE&G PSNC Description
10.06 X Description of SCANA Whole Life Option (Filed as
Exhibit 10-F to Form 10-K for the year ended
December 31, 1991, under cover of Form SE, File
No. 1-8809)
10.07 X Description of SCANA Corporation Executive Annual
Incentive Plan (Filed as Exhibit 10-G to Form 10-K
for the year ended December 31, 1991, under cover
of Form SE, File No. 1-8809)
10.08 X SCANA Corporation Director Compensation and
Deferral Plan effective January 1, 2001 (Filed as
Exhibit 10.05 to Registration Statement No.
333-49960)
10.09 X Operating Agreement of Pine Needle LNG Company,
LLC dated August 8, 1995 (Filed as Exhibit 10.01
to Registration Statement No. 333-45206)
10.10 X Amendment to Operating Agreement of Pine Needle
LNG Company, LLC dated October 1, 1995 (Filed as
Exhibit 10.02 to Registration Statement No.
333-45206)
10.11 X Amended Operating Agreement of Cardinal Extension
Company, LLC dated December 19, 1996 (Filed as
Exhibit 10.03 to Registration Statement No.
333-45206)
10.12 X Amended Construction, Operation and Maintenance
Agreement by and between Cardinal Operating
Company and Cardinal Extension Company, LLC dated
December 19, 1996 (Filed as Exhibit 10.04 to
Registration Statement No. 333-45206)
10.13 X Form of Severance Agreement between PSNC and its
Executive Officers (Filed as Exhibit 10.05 to
Registration Statement No. 333-45206)
10.14 X Service Agreement between PSNC and SCANA Services,
Inc., effective April 1, 2001 (Filed as Exhibit
10.06 to Registration Statement No. 333-45206)
10.15 X Service Agreement between SCE&G and SCANA
Services, Inc., effective April 1, 2002
(Filed herewith)
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)