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