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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
------------ --------------------------------
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-11429 Public Service Company of North Carolina, Incorporated 56-2128483
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
Indicate by check mark whether the registrants: (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the last practicable date.
Description of Shares Outstanding
Registrant Common Stock at July 31, 2002
- ---------- ------------ -------------------------
SCANA Corporation Without Par Value 104,732,446
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).
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2
INDEX
Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section........................................ 3
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of
June 30, 2002 and December 31, 2001 ...................... 4
Condensed Consolidated Statements of Operations
for the Periods Ended June 30, 2002 and 2001.............. 6
Condensed Consolidated Statements of Cash Flows
for the Periods Ended June 30, 2002 and 2001.............. 7
Condensed Consolidated Statements of Comprehensive
Income (Loss) for the Periods
Ended June 30, 2002 and 2001............................... 8
Notes to Condensed Consolidated Financial Statements......... 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................. 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk....... 28
South Carolina Electric & Gas Company Financial Section................... 30
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as
of June 30, 2002 and December 31, 2001 .................... 31
Condensed Consolidated Statements of Income
for the Periods Ended June 30, 2002 and 2001............... 33
Condensed Consolidated Statements of Cash
Flows for the Periods Ended June 30, 2002 and 2001......... 34
Notes to Condensed Consolidated Financial Statements......... 35
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 40
Item 3. Quantitative and Qualitative Disclosures About Market Risk........ 45
Public Service Company of North Carolina, Incorporated Financial Section... 46
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as
of June 30, 2002 and December 31, 2001 ..................... 47
Condensed Consolidated Statements of Operations
for the Periods Ended June 30, 2002 and 2001................ 48
Condensed Consolidated Statements of Cash Flows
for the Periods Ended June 30, 2002 and 2001............... 49
Notes to Condensed Consolidated Financial Statements.............. 50
Item 2. Management's Narrative Analysis of Results of Operations.......... 54
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.................................................. 56
Item 4. Submission of Matters to a Vote of Security-Holders................ 56
Item 6. Exhibits and Reports on Form 8-K................................... 57
Signatures.................................................................. 58
Exhibit Index............................................................... 61
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------
June 30, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Assets
Utility Plant:
Electric $5,154 $4,855
Gas 1,543 1,536
Other 195 187
- --------------------------------------------------------------------------------
Total 6,892 6,578
Accumulated depreciation and amortization (2,440) (2,364)
- --------------------------------------------------------------------------------
Total 4,452 4,214
Construction work in progress 478 544
Nuclear fuel, net of accumulated amortization 50 45
Acquisition adjustments, net of accumulated amortization 460 460
- --------------------------------------------------------------------------------
Utility Plant, Net 5,440 5,263
- --------------------------------------------------------------------------------
Nonutility Property, Net of Accumulated Depreciation 89 93
Investments 191 191
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 280 284
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 404 212
Receivables (net of allowance for uncollectible
accounts of $33 in 2002 and $37 in 2001) 381 424
Inventories (at average cost):
Fuel 138 164
Materials and supplies 60 59
Emission allowances 13 13
Prepayments 31 21
Investments 170 664
- --------------------------------------------------------------------------------
Total Current Assets 1,197 1,557
- --------------------------------------------------------------------------------
Deferred Debits:
Environmental 31 34
Nuclear plant decommissioning fund 83 79
Pension asset, net 252 239
Other regulatory assets 223 210
Other 162 156
- --------------------------------------------------------------------------------
Total Deferred Debits 751 718
- --------------------------------------------------------------------------------
Total $7,668 $7,822
================================================================================
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- -------------------------------------------------------------- -----------------
June 30, December 31,
Millions of dollars 2002 2001
- -------------------------------------------------------------- -----------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,150 $2,194
Preferred stock (Not subject to
purchase or sinking funds) 106 106
- -------------------------------------------------------------- -----------------
Total Stockholders' Investment 2,256 2,300
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 2,993 2,646
- -------------------------------------------------------------- -----------------
Total Capitalization 5,309 5,006
- -------------------------------------------------------------- -----------------
Current Liabilities:
Short-term borrowings 213 165
Current portion of long-term debt 396 739
Accounts payable 237 275
Customer deposits 46 41
Taxes accrued 39 82
Interest accrued 56 45
Dividends declared 36 34
Deferred income taxes, net 30 154
Other 26 26
- -------------------------------------------------------------- -----------------
Total Current Liabilities 1,079 1,561
- -------------------------------------------------------------- -----------------
Deferred Credits:
Deferred income taxes, net 736 720
Deferred investment tax credits 116 118
Reserve for nuclear plant decommissioning 83 79
Postretirement benefits 127 122
Other regulatory liabilities 103 100
Other 115 116
- -------------------------------------------------------------- -----------------
Total Deferred Credits 1,280 1,255
- -------------------------------------------------------------- -----------------
Total $7,668 $7,822
============================================================== =================
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- --------------------------------------------------------------------------- ------------------------- -------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars, except per share amounts 2002 2001 2002 2001
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Operating Revenues:
Electric $349 $340 $651 $681
Gas - regulated 155 175 451 642
Gas - nonregulated 145 225 369 736
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Total Operating Revenues 649 740 1,471 2,059
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Operating Expenses:
Fuel used in electric generation 92 68 166 135
Purchased power 16 39 21 87
Gas purchased for resale 234 333 613 1,148
Other operation and maintenance 131 122 258 251
Depreciation and amortization 55 56 108 112
Other taxes 32 29 63 59
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Total Operating Expenses 560 647 1,229 1,792
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Operating Income 89 93 242 267
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Other Income (Loss):
Other income, including allowance for equity funds
used during construction 20 18 37 31
Gain on sale of investments and assets 15 546 31 555
Impairment of investments (11) - (255)
-
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Total Other Income (Loss) 24 564 (187) 586
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 113 657 55 853
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction 51 59 102 121
Preferred Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 1 2 2
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Income (Loss) Before Income Taxes and Preferred Stock Dividends 61 597 (49) 730
Income Tax Expense (Benefit) 19 210 (21) 262
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Income (Loss) Before Preferred Stock Dividends 42 387 (28) 468
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 2 2 4 4
- --------------------------------------------------------------------------- ----------- ------------- ----------- -------------
Net Income (Loss) $40 $385 $(32) $464
=========================================================================== =========== ============= =========== =============
=========================================================================== =========== ============= =========== =============
Basic and Diluted Earnings (Loss) Per Share $.38 $3.67 $(.30) $4.42
Weighted Average Shares Outstanding (millions) 104.7 104.7 104.7 104.7
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- ------------------------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2002 2001
- -------------------------------------------------------------------------------- ---------------
Cash Flows From Operating Activities:
Net income (loss) $(32) $464
Adjustments to reconcile net income
(loss) to net cash provided from operating
activities:
Depreciation and amortization 113 116
Amortization of nuclear fuel 7 6
Gain on sale of investments and assets (31) (555)
Hedging activities 39 (46)
Impairment on investments 255 -
Allowance for funds used during construction (20) (9)
Over (under) collection, fuel adjustment clauses (21) 2
Changes in certain assets and liabilities:
(Increase) decrease in receivables 44 234
(Increase) decrease in inventories 25 (42)
(Increase) decrease in prepayments (10) (24)
(Increase) decrease in pension asset (13) (20)
(Increase) decrease in other regulatory assets (2) 3
Increase (decrease) in deferred income taxes, net (136) 220
Increase (decrease) in regulatory liabilities 17 5
Increase (decrease) in postretirement benefits 5 4
Increase (decrease) in accounts payable (38) (158)
Increase (decrease) in taxes accrued (43) (43)
Increase (decrease) in interest accrued 11 9
Other, net 21 (74)
- -------------------------------------------------------------------------------- ---------------
Net Cash Provided From Operating Activities 191 92
- -------------------------------------------------------------------------------- ---------------
Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (269) (183)
Proceeds from sale of investments and assets 336 26
Increase in nonutility property (7) (25)
Investments in affiliates (20) (28)
- -------------------------------------------------------------------------------- ---------------
- -------------------------------------------------------------------------------- ---------------
Net Cash Provided From (Used For) Investing Activities 40 (210)
- -------------------------------------------------------------------------------- ---------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149
Issuance of notes and loans 397 648
Repayments:
First and Refunding Mortgage Bonds (104) -
Notes and loans (605) (306)
Dividends and distributions:
Common stock (66) (61)
Preferred stock (4) (4)
Short-term borrowings, net 48 (282)
- -------------------------------------------------------------------------------- ---------------
Net Cash Provided From (Used For) Financing Activities (39) 144
- -------------------------------------------------------------------------------- ---------------
Net Increase In Cash and Temporary Investments 192 26
Cash and Temporary Investments, January 1 212 159
- -------------------------------------------------------------------------------- ---------------
Cash and Temporary Investments, June 30 $404 $185
================================================================================ ===============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $7 for 2002 and $5 for $89 $111
2001)
- Income taxes 105 41
Noncash Investing and Financing Activities:
Unrealized gain on securities available for sale, net of tax 30 255
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2002 2001 2002 2001
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Net Income (Loss) $40 $385 $(32) $464
Other Comprehensive Income (Loss),
net of tax:
Unrealized gains (losses) on
securities available for sale (64) (247) 29 (99)
Unrealized gains (losses) on
hedging activities 3 (34) 27 (53)
Cumulative effect of change in
accounting for hedging activities - - - 23
- --------------------------------------------------------------------------------
Total Comprehensive Income (Loss) (1) $(21) $104 $24 $335
================================================================================
(1) Accumulated other comprehensive loss of the Company totaled $(57) million
and $(113) million as of June 30, 2002 and December 31, 2001, respectively.
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2002
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in SCANA Corporation's (the Company)
Annual Report on Form 10-K for the year ended December 31, 2001. These are
interim financial statements, and due to the seasonality of the Company's
business, the amounts reported in the Condensed Consolidated Statements of
Operations are not necessarily indicative of amounts expected for the year. In
the opinion of management, the information furnished herein reflects all
adjustments, all of a normal recurring nature, which are necessary for a fair
statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result, the Company has
recorded as of June 30, 2002 approximately $254 million and $103 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets, and liabilities of approximately $141 million and
$90 million, respectively. The electric and gas regulatory assets of
approximately $56 million and $57 million, respectively (excluding deferred
income tax assets), are recoverable through rates. The Public Service Commission
of South Carolina (SCPSC) and the North Carolina Utilities Commission (NCUC)
have reviewed and approved most of the items shown as regulatory assets through
specific orders. Other items represent costs which are not yet approved for
recovery by the SCPSC or the NCUC, but are the subject of current or future
filings. In recording these costs as regulatory assets, management believes the
costs will be allowable under existing rate-making concepts that are embodied in
current rate orders received by the Company. However, ultimate recovery is
subject to SCPSC or NCUC approval. In the future, as a result of deregulation or
other changes in the regulatory environment, the Company may no longer meet the
criteria for continued application of SFAS 71 and could be required to write off
its regulatory assets and liabilities. Such an event could have a material
adverse effect on the Company's results of operations in the period the
write-off would be recorded, but it is not expected that cash flows or financial
position would be materially affected.
B. New Accounting Standards
The Company adopted SFAS 141, "Business Combinations," and SFAS 142,
"Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141
requires all acquisitions to be accounted for utilizing the purchase method. The
Company considers the amounts categorized by the Federal Energy Regulatory
Commission (FERC) as "acquisition adjustments" to be goodwill as defined in SFAS
142 and ceased amortization of such amounts upon the adoption of SFAS 142. This
amortization is related to acquisition adjustments of approximately $466 million
carried on the books of Public Service Company of North Carolina, Incorporated
(PSNC) and approximately $40 million carried on the books of South Carolina
Pipeline Corporation (SCPC). The Company has no other intangible assets subject
to amortization as provided in SFAS 142.
If the Company had ceased amortization during all periods presented in
the condensed consolidated statements of operations, net income (loss) and basic
and diluted earnings (loss) per share would have been as follows:
Three Months Ended Six Months Ended
June 30, June 30,
(Millions of dollars, except per share amounts) 2002 2001 2002 2001
---- ---- ---- ----
Net Income (Loss) as Reported $40 $385 $(32) $464
Amortization of Acquisition Adjustment 4 7
---- ------ - ------ ------ -
- -
-- -
Net Income (Loss) as Adjusted $40 $389 $(32) $471
=== ==== ===== ====
Basic and Diluted Earnings (Loss) Per Share As Reported $.38 $3.67 $(.30) $4.42
Amortization of Acquisition Adjustment - .03 - .07
----- - --- --- ------- ----- ---
Basic and Diluted Earnings (Loss) Per Share As Adjusted $.38 $3.70 $(.30) $4.49
==== ===== ===== =====
SFAS 142 provides a six-month transitional period from the effective
date of adoption for the Company to perform an assessment of whether there is an
indication that goodwill is impaired. The Company's initial analysis indicated
that a write down of the acquisition adjustment associated with PSNC ranging
from $200 million to $250 million will be required. The final valuation analysis
will be completed by December 31, 2002, and any write-down resulting from the
analysis will be recorded as the cumulative effect of a change in accounting
principle.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing liabilities related to the future
obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective
January 1, 2003. The impact SFAS 143 may have on the Company's financial
position has not been determined but could be material. Because any ARO
anticipated to be recorded would relate to regulated operations, it is not
expected that the adoption of the statement will have any impact on results of
operations or cash flows.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," became effective January 1, 2002. This statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
SFAS 145, "Rescission of SFASs 4, 44 and 64, Amendment of SFAS 13, and
Technical Corrections," was issued in April 2002. The provisions of SFAS 145,
among other things, discontinue treating gains or losses from the early
extinguishment of debt as extraordinary items unless such early extinguishment
meets the criteria of Accounting Principles Board Opinion (APB) 30. The Company
will adopt SFAS 145 effective January 1, 2003 and does not expect that such
adoption will have any impact on the Company's results of operations, cash flows
or financial position.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. This statement requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that such adoption will have any impact on the Company's results of operations,
cash flows or financial position.
C. Stock Option Plan
The Company sponsors the SCANA Corporation Long-Term Equity
Compensation Plan (the Plan), under which certain employees and non-employee
directors may receive nonqualified stock options and other forms of equity
compensation. The Company accounts for this equity-based compensation under APB
25, "Accounting for Stock Issued to Employees" related interpretations. In
addition, the Company has adopted the disclosure provisions of SFAS 123,
"Accounting for Stock-Based Compensation." At June 30, 2002, options issued and
outstanding under the Plan totaled approximately 1.9 million.
D. Earnings (Loss) Per Share
Earnings (loss) per share amounts have been computed in accordance with
SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings (loss) per share
are computed by dividing net income (loss) by the weighted average number of
common shares outstanding for the period. Diluted earnings (loss) per share are
computed as net income (loss) divided by the weighted average number of shares
of common stock outstanding during the period after giving effect to securities
considered to be dilutive potential common stock. The Company uses the treasury
stock method in determining total dilutive potential common stock.
E. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company (SCE&G)
Electric
In April 2002 the SCPSC approved SCE&G's request to increase the fuel
component of rates charged to electric customers from 1.579 cents per
kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2002 through April 2003. The increase
also provides recovery for under-collected actual fuel costs through April 2002,
including short-term purchased power costs necessitated by outages at two of
SCE&G's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002.
In September 1999 the SCPSC 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 SCPSC 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 SCPSC. Any unused portion of the $36 million in any given year may be
carried forward for possible use in the following year. As of June 30, 2002 no
accelerated depreciation has been recorded. The accelerated capital recovery
plan will be accomplished through existing customer rates.
Gas
SCE&G's rates are established using a cost of gas component approved by
the SCPSC which may be modified periodically to reflect changes in the price of
natural gas purchased by SCE&G.
SCE&G's cost of gas component in effect during the period January 1,
2001 through June 30, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-June 2002
In 1994 the SCPSC issued an order approving SCE&G's request to recover,
through a billing surcharge to its gas customers, the costs of environmental
cleanup at the sites of former manufactured gas plants (MGPs). The billing
surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for SCE&G's gas operations that had previously
been deferred. In October 2001, as a result of the annual review, the SCPSC
approved SCE&G'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 June 30, 2002 ($20.6 million) prior to the end of 2005.
Public Service Company of North Carolina, Incorporated (PSNC)
PSNC's rates are established using a benchmark cost of gas approved by
the NCUC, which may be modified periodically to reflect changes in the market
price of natural gas and changes in the rates charged by PSNC's pipeline
transporters. 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 NCUC reviews PSNC's gas purchasing practices annually.
PSNC's benchmark cost of gas in effect during the period January 1,
2001 through June 30, 2002 was as follows:
Rate Per Therm Effective Date
$.690 January 2001
$.750 February-March 2001
$.650 April-August 2001
$.500 September-October 2001
$.350 November-December 2001
$.300 January 2002
$.215 February-June 2002
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund to
extend natural gas service to Madison, Jackson and Swain Counties, North
Carolina. PSNC estimates that the cost of this project will be approximately
$31.4 million. The Madison County portion of the project was completed at a cost
of approximately $5.8 million, and customers began receiving service in July
2001. Construction has begun in Jackson County, and approximately $0.9 million
in construction costs have been incurred through June 30, 2002.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately
$1 million in each of August 2000 and August 2001, and agreed to a moratorium on
general rate cases until August 2005. General rate relief can be obtained during
this period to recover costs associated with material adverse governmental
actions and force majeure events.
South Carolina Pipeline Corporation (SCPC)
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In July 2002, the SCPSC found that
for the period January 2001 through March 2002 SCPC's gas purchasing policies
and practices were prudent and the gas cost recovery provisions of its gas
tariff were properly adhered to.
3. LONG-TERM DEBT
On January 31, 2002 SCANA issued $250 million of medium-term notes
maturing February 1, 2012 and bearing a fixed interest rate of 6.25 percent.
Also on January 31, 2002 SCANA issued $150 million of two-year floating rate
notes maturing on February 1, 2004. The interest rate on the floating rate notes
is reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds
from these issuances were used to refinance $400 million of two-year floating
rate notes that matured on February 8, 2002, which had been issued to finance
SCANA's acquisition of PSNC.
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem on
March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent Series due
August 15, 2021.
4. RETAINED EARNINGS
The Company's Restated Articles of Incorporation do not limit the
dividends that may be payable on its common stock. However, the Restated
Articles of Incorporation of SCE&G 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 June 30, 2002
approximately $39 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.
5. FINANCIAL INSTRUMENTS
Investments
SCANA and certain of its subsidiaries hold investments in marketable
securities, some of which are subject to SFAS 115 mark-to-market accounting and
some of which are considered cost basis investments for which determination of
fair value historically has been considered impracticable. Equity holdings
subject to SFAS 115 are categorized as "available for sale" and are carried at
quoted market, with any unrealized gains and losses credited or charged to other
comprehensive income within common equity on the Company's balance sheet. Debt
securities are categorized as "held to maturity" and are carried at amortized
cost. When indicated, and in accordance with its stated accounting policy, SCANA
performs periodic assessments of whether any decline in the value of these
securities to amounts below SCANA's cost basis is other than temporary. When
other than temporary declines occur, write-downs are recorded through
operations, and new (lower) cost bases are established.
At June 30, 2002 SCANA and SCANA Communications Holdings, Inc. (SCH), a
wholly owned, indirect subsidiary of SCANA, held marketable equity and debt
securities in the following companies in the amounts noted in the table below.
As of June 30, 2002
Unrealized
Investee Held Securities (a) Basis Market Gain (Loss)
By (b)
- ------------------------------- -------------------------------------------------------------------- ------------- ---------------
(Millions of dollars)
DTAG SCH 18.3 million ordinary shares $258.0 $170.5 $(87.5)
ITC SCH 3.1 million shares common stock 5.8 (c) n/a
SCH 645,153 shares series A convertible preferred stock 7.2 (c) n/a
SCH 133,664 shares series B convertible preferred stock 4.0 (c) n/a
ITC^DeltaCom SCH 5.1 million shares common stock - - -
SCH 1.5 million shares series A convertible preferred stock - - -
SCANA 5,349 shares series B-1 preferred stock convertible into
938,418
shares of common stock - - -
SCANA 6,973 shares series B-2 preferred stock convertible into
2,723,828
shares of common stock - - -
SCANA Warrants to purchase approximately 1.0 million shares
common stock - - -
Knology SCH 7.2 million shares series A preferred stock, convertible into
7.5
million shares common stock 14.0 (c) n/a
SCH Warrants to purchase 159,180 shares series A convertible
preferred stock, convertible into 164,900 shares common - (c) n/a
stock
SCH 8.3 million shares series C preferred stock, convertible into
8.3
million shares common stock 15.6 (c) n/a
Knology
Broadband SCH $118,071,000 face amount, 11.875% Senior Discount notes due 82.1 (d) n/a
2007
(a) Convertible preferred stock is convertible into common stock at any time.
(b) Amounts are included in accumulated other comprehensive income (loss), net of taxes.
(c) Market value not readily determinable.
(d) Market value not readily determinable, classified as held to maturity.
Deutsche Telekom AG (DTAG) is an international telecommunications
carrier. On March 1, 2002 the Company determined that the decline in value of
its investment in DTAG to below its cost basis of $20.30 per share was other
than temporary, and recorded an impairment loss of approximately $160 million
(after tax). In March 2002 SCH sold 21 million ordinary shares of DTAG at a
weighted average price of $14.82 per share through a series of market
transactions. The sales resulted in net after tax proceeds of approximately $250
million.
ITC Holding Company (ITC) holds ownership interests in several Southeastern
communications companies. ITC^DeltaCom, Inc. (ITCD) is a regional provider of
telecommunications services and an affiliate of ITC. Knology, Inc. (Knology) is
a broadband service provider of cable television, telephone and internet
services. Knology is an affiliate of ITC. Knology Broadband, Inc. (Knology
Broadband) is a wholly-owned subsidiary of Knology and an affiliate of ITC.
In June 2002 ITCD announced plans for a reorganization and entered into
Chapter 11 bankruptcy. As a result the Company and SCH wrote off their
investments in ITCD in the second quarter resulting in an aggregate impairment
charge of approximately $7.0 million (after tax). Upon the bankruptcy court's
acceptance of the reorganization plan, the Company is committed to provide up to
$15 million in equity financing for ITCD.
In July 2002 Knology negotiated a potential exchange of its discount
notes for a combination of new notes and new preferred stock. As a result of the
anticipated exchange, the Company recorded an impairment loss of approximated
$0.3 million (after-tax). If the anticipated note restructuring occurs, the
Company has committed to purchase an additional 6.5 million shares of series C
preferred stock for approximately $19.5 million.
Derivatives
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires
the Company to recognize all derivative instruments as either assets or
liabilities in the statement of financial position and to measure those
instruments at fair value. SFAS 133 further provides that changes in the fair
value of derivative instruments are either recognized in earnings or reported as
a component of other comprehensive income, depending upon the intended use of
the derivative and the resulting designation.
The fair value of the derivative instruments is determined by reference
to quoted market prices of listed contracts, published quotations or quotations
from independent parties.
Risk limits are established to control the level of market, credit,
liquidity and operational and administrative risks assumed by the Company. The
Company's Board of Directors has delegated the authority for setting market risk
limits to a Risk Management Committee. The Risk Management Committee provides
assurance to the Board of Directors with regard to compliance with risk
management policies and brings to the Board's attention any areas of concern.
Written policies define the physical and financial transactions that are
approved, as well as the authorization requirements and limits for those
transactions that are allowed.
Commodities
The Company uses derivative instruments to hedge anticipated future
purchases of natural gas, which create market risks of different types.
Instruments designated as cash flow hedges are used to hedge risks associated
with fixed price obligations in a volatile price market and risks associated
with price differentials at different delivery locations. The basic types of
financial instruments utilized are exchange-traded instruments, such as New York
Mercantile Exchange futures contracts or options and over-the-counter
instruments such as swaps, which are typically offered by energy and financial
institutions.
As a result of adopting SFAS 133, the Company recorded a credit to other
comprehensive income of approximately $23.0 million, net of tax, as the effect
of a change in accounting principle (transition adjustment) on January 1, 2001.
This amount represents the reclassification of unrealized gains that were
deferred and reported as liabilities at December 31, 2000. Substantially all of
this amount was reclassified into earnings in 2001 as a component of gas cost.
The Company recognized losses of approximately $2.9 million and $21.9
million, net of tax, as a result of qualifying cash flow hedges whose hedged
transactions occurred during the three and six months ended June 30, 2002,
respectively. The Company recognized a loss of approximately $0.3 million and a
gain of approximately $4.6 million, net of tax, as a result of qualifying cash
flow hedges whose hedged transactions occurred during the three and six months
ended June 30, 2001, respectively. These gains and losses were recorded in cost
of gas. The Company estimates that most of the June 30, 2002 unrealized loss
balance of $0.4 million, net of tax, will be reclassified from accumulated other
comprehensive income to earnings in 2002 as a realized gas cost increase if
market prices remain stable. As of June 30, 2002 substantially all of the
Company's cash flow hedges settle by their terms before the end of 2005.
Certain derivatives that SCPC utilizes to hedge its gas purchasing
activities are recoverable through its weighted average cost of gas calculation.
Accordingly, the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
The Company also utilizes certain derivative instruments that do not
qualify as hedges. The change in fair value of these derivatives is recorded in
net income and was insignificant in the periods presented.
Interest Rates
In May 2001 the Company entered into an interest rate swap agreement to
pay variable rate and receive fixed rate interest payments on a notional amount
of $300 million. This swap was designated as a fair value hedge of the $300
million medium-term notes also issued in May. The swap agreement was terminated
and replaced with another swap agreement to pay variable rate and receive fixed
rate interest payments, also designated as a fair value hedge, in August 2001.
At June 30, 2002 the estimated fair value of this swap was $13.4 million. In
August 2001 the Company received $6.5 million to terminate the original swap.
The $6.5 million basis adjustment of the related debt is being amortized as a
reduction to interest expense over the ten-year term of the $300 million
medium-term notes.
In December 2001 PSNC entered into two interest rate swap agreements to
pay variable rate and receive fixed rate interest payments on a combined
notional amount of $44.9 million. These swaps were designated as fair value
hedges of PSNC's $12.9 million, 10 percent senior debenture due 2004 and $32.0
million, 8.75 percent senior debenture due 2012. At June 30, 2002 the estimated
fair value of these swaps was $0.9 million.
The fair value of these interest rate swaps is reflected within other
deferred debits on the balance sheet. The corresponding hedged fair value change
of the debt is also recorded on the balance sheet. The receipts or payments
related to the interest rate swaps are credited or charged to interest expense
as incurred.
6. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 13 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001. Commitments and contingencies at June 30, 2002 include
the following:
A. Lake Murray Dam Reinforcement
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam
in order to maintain the lake in case of an extreme earthquake. Construction for
the project and related activities, which began in the third quarter of 2001 is
expected to cost approximately $250 million and be completed in 2005.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public
liability for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 million of the liability per reactor would be
assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership
of 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 Santee
Cooper) with Nuclear Electric Insurance Limited. The policies, covering the
nuclear facility for property damage, excess property damage and outage costs,
permit assessments under certain conditions to cover insurer's losses. Based on
the current annual premium, SCE&G's portion of the retrospective premium
assessment would not exceed $15.5 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and expenses arising
from a nuclear incident at Summer Station exceed the policy limits of insurance,
or to the extent such insurance becomes unavailable in the future, and to the
extent that SCE&G's rates would not recover the cost of any purchased
replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G
has no reason to anticipate a serious nuclear incident at Summer Station. If
such an incident were to occur, it would have a material adverse impact on the
Company's results of operations, cash flows and financial position.
C. Environmental
The Company maintains an environmental assessment program to identify
and evaluate current and former operations sites that could require
environmental cleanup. As site assessments are initiated, estimates are made of
the amount of expenditures, if any, deemed necessary to investigate and clean up
each site. These estimates are refined as additional information becomes
available; therefore, actual expenditures could differ significantly from the
original estimates. Amounts estimated and accrued to date for site assessments
and cleanup relate primarily to regulated operations.
South Carolina Electric & Gas Company
In September 1992 the Environmental Protection Agency (EPA) notified
SCE&G, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of SCE&G's decommissioned MGPs.
Field work at the site began in November 1993 and has required the submission of
several investigative reports and the implementation of several work plans. In
September 2000, SCE&G was notified by the South Carolina Department of Health
and Environmental Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park area site.
The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility
Study on the intermediate aquifer, which was completed in June 2001. The EPA
expects to issue a Record of Decision dealing with the intermediate aquifer and
sediments in late 2002. SCE&G anticipates that major remediation activities will
be completed in 2003, with certain monitoring activities continuing until 2007.
As of June 30, 2002, SCE&G has spent approximately $17.9 million to remediate
the Calhoun Park area site. Total remediation costs are estimated to be $21.9
million.
SCE&G owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. Two of these sites are currently being
remediated under work plans approved by DHEC. SCE&G is continuing to investigate
the remaining site and is monitoring the nature and extent of residual
contamination. SCE&G anticipates that major remediation activities for these
three sites will be completed before 2006. SCE&G has spent approximately $2.0
million related to these sites and expects to spend an additional $6.0 million.
Public Service Company of North Carolina, Incorporated
PSNC owns, or has owned, all or portions of seven sites in North
Carolina on which MGPs were formerly operated. Intrusive investigation
(including drilling, sampling and analysis) has begun at two sites and the
remaining sites have been evaluated using historical records and observations of
current site conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. PSNC estimates the cost to
remediate the sites to be between $11.3 million and $21.9 million. 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 potentially responsible
parties (PRPs). At June 30, 2002 PSNC has recorded a liability and associated
regulatory asset of $8.9 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 $1.2 million.
Management believes that all MGP cleanup costs will be recoverable through gas
rates.
D. Telecommunications Investments
For a discussion of commitments related to the Company's
telecommunications investments, see Note 5.
7. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The
Company uses operating income to measure profitability for its regulated
operations. Therefore, net income is not allocated to the Electric Operations,
Gas Distribution and Gas Transmission segments. The Company uses net income to
measure profitability for its Retail Gas Marketing and Energy Marketing
segments. Affiliate revenue is derived from transactions between reportable
segments as well as transactions between separate legal entities that are
combined into the same reportable segment. Accumulated depreciation is not
assignable to Electric Operations and Gas Distribution segments. Gas
Distribution is comprised of the local distribution operations of SCE&G and PSNC
and meets SFAS 131 criteria for aggregation.
Disclosure of Reportable Segments
(Millions of dollars)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Three Months Ended External Intersegment Operating Net Segment
June 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $349 $145 $86 n/a $5,245
Gas Distribution 85 17 (2) n/a 1,611
Gas Transmission 70 40 6 $3 290
Retail Gas Marketing 111 - n/a 1 63
Energy Marketing 34 - n/a (2) 64
Telecommunications Investments - - - (3) 307
All Other - 1 - 4 484
Adjustments/Eliminations - (203) (1) 37 (396)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $649 - $89 $40 $7,668
================================== ============= ============== =============== ================= ===============
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Six Months Ended External Intersegment Operating Net Segment
June 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Electric Operations $651 $293 $174 n/a $5,245
Gas Distribution 325 18 52 n/a 1,611
Gas Transmission 126 113 (3) $(2) 290
Retail Gas Marketing 296 - n/a 15 63
Energy Marketing 73 - n/a (3) 64
Telecommunications Investments - - - (153) 307
All Other - 3 - 3 484
Adjustments/Eliminations - (427) 19 108 (396)
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Consolidated Total $1,471 - $242 $(32) $7,668
============================================ ============== =============== ================= ===============
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Three Months Ended External Intersegment Operating Net Segment
June 30, 2001 Revenue Revenue Income (Loss) Income (Loss) Assets
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Electric Operations $340 $133 $94 n/a $4,790
Gas Distribution 125 - (7) n/a 1,606
Gas Transmission 50 47 4 $ 2 288
Retail Gas Marketing 121 - n/a (5) 114
Energy Marketing 104 - n/a 6 126
Telecommunications Investments - - - 352 1,023
All Other - - - (6) 430
Adjustments/Eliminations - (180) 2 36 (529)
- -------------------------------------------- -------------- --------------- ----------------- ---------------
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Consolidated Total $740 - $93 $385 $7,848
============================================ ============== =============== ================= ===============
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Six Months Ended External Intersegment Operating Net Segment
June 30, 2001 Revenue Revenue Income Income Assets
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Electric Operations $681 $272 $191 n/a $4,790
Gas Distribution 510 1 53 n/a 1,606
Gas Transmission 132 166 4 $1 288
Retail Gas Marketing 384 - n/a 7 114
Energy Marketing 352 - n/a 5 126
Telecommunications Investments - - - 349 1,023
All Other - - - (12) 430
Adjustments/Eliminations - (439) 19 114 (529)
- -------------------------------------------- -------------- --------------- ----------------- ---------------
- -------------------------------------------- -------------- --------------- ----------------- ---------------
Consolidated Total $2,059 - $267 $464 $7,848
============================================ ============== =============== ================= ===============
============================================ ============== =============== ================= ===============
8. SUBSEQUENT EVENTS
A. On August 2, 2002 the Company filed a registration statement with the
Securities and Exchange Commission for the proposed issuance and sale of up to
6,000,000 shares of SCANA Common Stock. The offering is expected to be concluded
in the fall of 2002. Net proceeds from the sale will be contributed to the
equity capital of SCE&G or used for general corporate purposes.
B. On August 6, 2002 SCE&G filed an application with the SCPSC requesting a $105
million increase in retail electric revenues. The electric rate request is
largely associated with the power generation projects at SCE&G's recently
completed Urquhart Station and the generating station currently under
construction in Jasper County. It also includes costs for equipment required for
environmental and air quality improvements.
C. The Company is planning to issue $100 million one-year floating rate medium
term notes on August 15, 2002 maturing on August 15, 2003. The interest rate on
the notes is expected to be reset quarterly based on a three-month LIBOR plus
87.5 basis points. The proceeds will be used for general corporate purposes.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- -------------------------------------------------------------------------------
SCANA CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations
appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for
the year ended December 31, 2001.
Statements included in this discussion and analysis (or elsewhere in
this quarterly report) which are not statements of historical fact are intended
to be, and are hereby identified as, "forward-looking statements" for purposes
of the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility and nonutility
regulatory environment, (3) changes in the economy, especially in areas served
by the Company's subsidiaries, (4) the impact of competition from other energy
suppliers, (5) growth opportunities for the Company's regulated and diversified
subsidiaries, (6) the results of financing efforts, (7) changes in the Company's
accounting policies, (8) weather conditions, especially in areas served by the
Company's subsidiaries, (9) performance of and marketability of the Company's
investments in telecommunications companies, (10) 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 SEC. The Company disclaims any
obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2002.
Further, while several companies have announced their intent to site merchant
generating plants in the Company's service territory, economic events,
environmental concerns and other factors have slowed those efforts. At the
Federal level, energy legislation has passed both houses of Congress in 2002,
though significant differences exist between the House and Senate versions.
Among other things, this legislation would require that one percent of the
electric energy sold by retail electric suppliers be generated from renewable
energy resources beginning in 2005. This requirement would gradually escalate to
ten percent in 2019. Substantial penalties would be levied for failure to
comply. Electric cooperatives and municipal utilities would be exempt from these
requirements. In addition, on July 31, 2002, FERC proposed new rules aimed at
creating a standard market design for wholesale electric markets. See Other
Matters-Regional Transmission Organization, in this Management's Discussion and
Analysis of Financial Conditions and Results of Operations. The Company is not
able to predict whether these or similar legislative or regulatory actions will
be enacted and, if they are, the impact they will have on the Company.
Gas Transmission
SCG Pipeline, Inc. (SCG), when operational, will provide interstate
transportation services for natural gas to markets in southeastern Georgia and
South Carolina. SCG will transport natural gas from interconnections with
Southern Natural at Port Wentworth, Georgia, and from an import terminal owned
by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's
line will be at the site of the natural gas-fired generating station that SCE&G
is building in Jasper County, South Carolina. In June 2002 SCG received
preliminary approval from FERC to acquire and build a pipeline from Elba Island,
Georgia to Jasper County, South Carolina. Final approval is pending. The project
has an anticipated in-service date of November 2003.
Retail Gas Marketing
In April 2002 Georgia's Governor signed into law the Natural Gas
Consumer's Relief Act of 2002 (the Act). The Act attempts to resolve many of the
issues surrounding Georgia's deregulated natural gas market with the following
significant provisions:
o creates a regulated provider selected through a bidding process to serve
low-income and high credit risk customers, o allows Georgia's 42 non-profit
Electric Membership Corporations (EMC) to set up natural gas affiliates that may
seek
certification as marketers of natural gas,
o establishes new service quality standards and addresses assignment of
interstate assets, and o gives the Georgia Public Service Commission (GPSC) the
authority to temporarily regulate rates if more than 90% of customers in a
specific area of the state are served by three or fewer marketers.
The GPSC is responsible for implementing and monitoring most of the
Act's provisions. While SCANA Energy believes the Act represents a balanced
approach in addressing deregulation issues for consumers and marketers, the
impact the Act will have on SCANA Energy and Georgia's natural gas market cannot
be predicted until more details of GPSC's implementation become known.
In June 2002 SCANA Energy won GPSC approval to become the State's
regulated provider. In this capacity, SCANA Energy will serve low-income
customers at below-market rates subsidized by Georgia's Universal Service Fund,
and it will extend service at above-market rates to high-risk customers who have
been denied service by other marketers.
In June 2002 the fourth largest marketer in Georgia's natural gas market
declared bankruptcy. In July 2002 a subsidiary of Southern Company completed its
purchase of the bankrupt marketer's Georgia operations. Southern Company,
through a subsidiary, sells electricity to approximately two million customers
in Georgia. Southern Company is anticipated to be a significant competitor in
the Georgia natural gas market. In addition, in July 2002 one EMC applied to the
GPSC to become certified as a gas marketer.
SCANA Energy and SCANA's other natural gas distribution, transmission
and marketing segments maintain gas inventory and also utilize forward contracts
and financial instruments, including futures contracts, to manage their exposure
to fluctuating commodity natural gas prices. (See Note 5 of Notes to Condensed
Consolidated Financial Statements.) As a part of this risk management process, a
portion of SCANA's projected natural gas needs has been purchased or otherwise
placed under contract. This factor and others (e.g., the level of bad debts
experienced) are, in the aggregate, used to establish retail pricing levels at
SCANA Energy. As a result of the regulatory actions discussed above and other
downward pricing pressures inherent in the competitive market, SCANA Energy may
be unable to sustain its current levels of customers and/or pricing, thereby
reducing expected margins and profitability.
LIQUIDITY AND CAPITAL RESOURCES
The Company anticipates that its contractual cash obligations will be
met through internally generated funds, the incurrence of additional short-term
and long-term indebtedness and sales of additional equity securities. See Note 8
of Notes to Condensed Consolidated Financial Statements. The Company expects
that it has or can obtain adequate sources of financing to meet its projected
cash requirements for the foreseeable future. The Company's ratio of earnings to
fixed charges for the 12 months ended June 30, 2002 was 1.27.
On August 6, 2002 SCE&G filed an application with the Public Service
Commission of South Carolina (SCPSC) requesting a $104.7 million increase in
retail electric revenues. The electric rate request is largely associated with
the power generation projects at SCE&G's recently completed Urquhart Station and
the Jasper Generating Station currently under construction, both of which are
discussed below. It also includes costs for equipment required for environmental
and air quality improvements.
The following table summarizes how the Company generated and used funds
for property additions and construction expenditures during the six months ended
June 30, 2002 and 2001:
- --------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2002 2001
- --------------------------------------------------------------- ----------------
Net cash provided from operating activities $191 $92
Net cash provided from (used for)
financing activities (39) 144
Funds used for investments in
equity securities (20) (28)
Cash provided from sale of investments and assets 336 26
Cash and temporary investments available at the
beginning of the period 212 159
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Net cash available for property additions
and construction expenditures $680 $393
===============================================================================
Funds used for utility property additions and
construction expenditures,
Net of noncash allowance for funds used
during construction $269 $183
Funds used for nonutility property additions 7 25
===============================================================================
On January 31, 2002 SCANA issued $250 million of medium-term notes
maturing February 1, 2012 and bearing a fixed interest rate of 6.25 percent.
Also on January 31, 2002 SCANA issued $150 million of two-year floating rate
notes maturing on February 1, 2004. The interest rate on the floating rate notes
is reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds
from these issuances were used to refinance $400 million of two-year floating
rate notes that matured on February 8, 2002, which had been issued to finance
SCANA's acquisition of PSNC.
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem on
March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent Series due
August 15, 2021.
On April 24, 2002 SCANA redeemed $202 million of floating rate
medium-term notes that were set to mature on January 24, 2003. The notes were
bearing interest of 2.90 percent at the time of redemption.
On July 15, 2002 SCANA retired at maturity $300 million of floating rate
medium-term notes. The notes were bearing interest of 4.063 percent at maturity.
The Company is planning to issue $100 million one-year floating rate
medium term notes on August 15, 2002 maturing on August 15, 2003. The interest
rate on the notes is expected to be reset quarterly based on a three-month LIBOR
plus 87.5 basis points. The proceeds will be used for general corporate
purposes.
SCE&G placed in service a $248 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 340 megawatts of new electric generation and use exhaust
heat to replace coal-fired steam that powers two existing 75 megawatt turbines
at the Urquhart Generating Station.
In 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order
to maintain the lake in case of an extreme earthquake. Construction for the
project and related activities, which began in the third quarter of 2001, is
expected to cost approximately $250 million and be completed in 2005.
In May 2002 SCE&G began construction of an 875 megawatt generation
facility in Jasper County, South Carolina, to supply electricity to its South
Carolina customers. The facility will include three natural gas
combustion-turbine generators and one steam-turbine generator. The $450 million
facility is expected to begin commercial operation in the summer of 2004, and
SCG Pipeline, Inc., will transport natural gas to the facility. 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 nine years
beginning January 1, 2004.
SECURITIES RATINGS (As of July 31, 2002)
SCANA SCE&G PSNC
- ------------------------------------------- ------------------------------------------ --- ----------------------
- ----------------------------------- --------------------------------- ------------- ------------- ---------------
First and
Medium- First Refunding Trust
Rating Term Mortgage Mortgage Preferred Preferred Commercial Senior Commercial
Agency Notes Bonds Bonds Stock Securities Paper Unsecured Paper
------ ----- ----- ----- ----- ---------- ----- --------- -----
Moody's A3 A1 A1 Baa1 A3 P-1 A2 P-1
Standard & Poor's BBB+ A- A- BBB BBB A-1 A- A-1
Fitch Ratings A- A+ A+ A A F-1 n/a n/a
- ----------------------------------- --------------------------------- ------------- ------------- ---------------
These ratings reflect the downgrade issued by Standard & Poor's on July
31, 2002. The Company does not expect the downgrade to adversely impact the
Company's liquidity.
ENVIRONMENTAL MATTERS
For information on environmental matters see Note 6C of Notes to
Condensed Consolidated Financial Statements.
OTHER MATTERS
Regional Transmission Organization (RTO)
In June 2002 the Company and the other two electric utilities that
formed GridSouth Transco LLC (GridSouth) suspended implementation of GridSouth.
Though the three companies continue to support the RTO concept, GridSouth
implementation was suspended pending the issuance and evaluation of new FERC
directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR)
which further defines FERC's new standard market design for wholesale electric
markets, including bidding rules and other measures to create a common market
framework. The Company is currently evaluating this NOPR to determine what
effect it will have on the Company's operations. Additional directives from FERC
are expected later in 2002.
Radio Service Network
In April 2002 SCI sold its 800 Mhz radio service network within South
Carolina to Motorola, Inc. for an after tax gain of approximately $9 million.
Telecommunications Investments
In June 2002 ITC^DeltaCom, Inc. (ITCD) announced plans for a
reorganization and entered into Chapter 11 bankruptcy. As a result the Company
and SCH wrote off their investments in ITCD in the second quarter (see Note 5 of
Notes to Condensed Consolidated Financial Statements). Upon the bankruptcy
court's acceptance of the reorganization plan, the Company is committed to
provide up to $15 million in equity financing for ITCD which will result in the
Company owning approximately 7% of the reorganized ITCD.
In July 2002 Knology, Inc. (Knology) negotiated a potential exchange of
its discount notes for a combination of new notes and new preferred stock. As a
result of the anticipated exchange, the Company recorded an impairment loss of
approximately $0.3 million (after-tax). If the anticipated note restructuring
occurs, the Company has committed to purchase an additional 6.5 million shares
of series C preferred stock for approximately $19.5 million. This purchase is
expected to occur before year end, and will result in the Company owning a 13%
voting interest in Knology.
For more information on telecommunications investments, see Note 5 of
Notes to Condensed Consolidated Financial Statements.
Nuclear Station License Extension
In August 2002 SCE&G filed an application with the Nuclear Regulatory
Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear
Station. If approved, the extension would allow the plant to operate through
2042.
Transit
SCE&G and the City of Columbia, South Carolina (City) have entered into
an agreement under which a regional transit authority is expected to take over
operation of SCE&G's transit system effective August 31, 2002. As part of the
agreement, SCE&G will pay the City $32 million over seven years in exchange for
a 30-year electric and gas franchise, will convey transit-related property and
equipment to the City and will convey the historic Columbia Canal and
Hydroelectric Plant to the City. The transaction has been approved by the SCPSC
and the SEC, but is still subject to approval by FERC and other customary
conditions to closing.
Stock Purchase-Savings Plan
Between April 17, 2002 and August 1, 2002 265,814 shares of the
Company's no par value common stock ("Common Stock") were purchased in open
market transactions by AMVESCAP National Trust Company as Trustee of the
Company's Stock Purchase-Savings Plan (the "Plan"). These shares were purchased
for the accounts of those employees of the Company and its subsidiaries that
participate in the Plan. Under the terms of the Plan, employees may contribute
up to 15% of their "eligible earnings" to the Plan and the Company matches the
first 6% of such contributions on a dollar-for-dollar basis. The Company
believes that the open market purchase of shares by the Trustee should not be
deemed to be an offer or sale of securities subject to the registration
requirements of the Securities Act of 1933, as amended. Nevertheless, because
the matter is not free from doubt and because the Plan provides for original
issue purchases as well as open market purchases, the Company filed a
registration statement on August 2, 2002, on Form S-8 (333-97555) registering
5,000,000 shares of Common Stock for sale under the Plan.
RESULTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2002
AS COMPARED TO THE CORRESPONDING PERIOD IN 2001
Earnings (Loss) Per Share
Earnings (loss) per share of common stock for the second quarter and
year to date periods ended June 30, 2002 and 2001 were as follows:
- ---------------------------------------------------------------------------- -----------------------------
Second Quarter Year to Date
2002 2001 2002 2001
- -------------------------------------------------------------- ------------- -------------
---------------
Earnings (loss) derived from:
Operations $.36 $.29 $1.10 $1.00
Non-recurring items:
Realized gain from stock investment - 3.38 .10 3.38
Sale of subsidiary assets .09 - .09 .04
Investment impairment (.07) $(1.59)
---------------
- -------------------------------------------------------------- ------------- ------------- ---------------
Earnings (loss) per weighted average share $.38 $3.67 $(.30) $4.42
============================================================== ============= ============= ===============
Second Quarter 2002 vs 2001
Earnings per share from operations increased $.07 primarily due to lower
interest expense of $.05, improved margins from sales of electricity of $.04,
increased allowance for funds used during construction of $.02, lower
depreciation and amortization expense of $.01 and other of $.01. These factors
were partially offset by higher operation and maintenance expenses of $.05 and
lower gas margins of $.01.
Earnings (loss) per share from non-recurring items included a $.09 gain
from the sale of a subsidiary's radio service network in April 2002 and a $.07
loss due to an impairment write-down of the Company's investment in ITCD in June
2002. In May 2001 the Company recognized a non-cash gain of $3.38 from the sale
of its investment in Powertel, Inc.
Year to Date 2002 vs 2001
Earnings (loss) per share from operations increased $.10 primarily due
to lower interest expense of $.11, improved margins from sales of electricity of
$.03, lower depreciation and amortization expense of $.02, increased allowance
for funds used during construction of $.05, improved results from non-regulated
subsidiaries of $.04, increased tax deductions from benefit plans of $.02 and
other increases of $.02. These factors were partially offset by lower gas
margins of $.13, higher operation and maintenance expenses of $.04, higher
property taxes of $.01 and other decreases of $.01.
Earnings (loss) per share from non-recurring items includes a second
quarter 2002 gain from the sale of the Company's radio service network of $.09
and loss from an impairment charge for the Company's investment in ITCD of $.07.
In addition, the Company recognized a non-recurring gain of $.10 per share in
connection with the sale of Deutsche Telekom AG (DTAG) ordinary shares in March
2002. In March 2002 the company also recorded an impairment write-down of $1.52
per share related to the other than temporary decline in market value of the
Company's investment in DTAG (see Note 5 of Notes to Condensed Consolidated
Financial Statements). In 2001 the Company recorded a gain from the sale of its
investment in Powertel, Inc. of $3.38 and a gain from the sale of the assets of
SCANA Security of $.04.
Pension Income
For the last several years, the market value of the Company's
retirement plan (pension) assets has exceeded the total actuarial present value
of accumulated plan benefits. Pension income in the second quarter and the year
to date periods of 2002 decreased significantly compared to corresponding
periods in 2001 primarily as a result of a less favorable investment market.
Pension income during these periods was recorded on the Company's financial
statements as follows:
- -------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 2002 2001
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Financial Statement Impact:
Reduction in employee benefit costs $3.3 $5.2 $6.9 $10.4
Increase in other income 1.8 3.0 3.9 6.0
Reduction in capital expenditures 1.0 1.4 1.9 2.9
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Total Pension Income $6.1 $9.6 $12.7 $19.3
====================================================================== ========
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of
both equity and borrowed funds used to finance construction (which is shown on
the balance sheet as construction work in progress) is capitalized. 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 16 percent and 42 percent of income (loss) before taxes and
preferred stock dividends for the three and six months ended June 30, 2002,
respectively, compared to one percent for both corresponding periods in 2001.
The increase in AFC is primarily the result of increased construction
expenditures related to the projects at Urquhart Station, Jasper County and Lake
Murray Dam (see discussion at LIQUIDITY AND CAPITAL RESOURCES) and the effect of
non-recurring items on income (loss) before tax for the periods.
Dividends Declared
The Company's Board of Directors declared the following dividends on
common stock during 2002:
- -------------------- --------------------- -------------------- ---------------
Declaration Date Dividend Per Share Record Date Payment Date
- -------------------- --------------------- -------------------- ---------------
February 21, 2002 $.325 March 8, 2002 April 1, 2002
May 2, 2002 $.325 June 10, 2002 July 1, 2002
August 1, 2002 $.325 September 10, 2002 October 1, 2002
- -------------------- --------------------- -------------------- ---------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G, South
Carolina Generating Company (GENCO) and South Carolina Fuel Company (Fuel
Company). Changes in the electric operations sales margins were as follows:
-----------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
-----------------------------------------------------------------------------------------------------------------------
Electric operating revenue $348.5 $340.5 $8.0 2.3% $651.1 $680.7 $(29.6) (4.3%)
Less: Fuel used in generation 91.5 67.9 23.6 34.8% 165.9 135.1 30.8 22.8%
Purchased power 16.3 39.0 (22.7) (58.2%) 21.4 87.5 (66.1) (75.5%)
----------------------------------------------------------------- --------------------------------
Margin $240.7 $233.6 $7.1 3.0% $463.8 $458.1 $5.7 1.2%
=======================================================================================================================
Second Quarter 2002 vs 2001
Margin increased due to more favorable weather. Fuel used in generation
increased and purchased power cost decreased due to the repowering project at
the Urquhart plant which was completed in June 2002 and higher utilization of
steam plants during the planned maintenance outage at Summer Station in 2002.
Year to Date 2002 vs 2001
Margin increased due to more favorable weather in the second quarter,
which was partially offset by less favorable weather in the first quarter. Fuel
used in generation increased and purchased power cost decreased due to more
plants being on line during the period.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC. Changes in the gas distribution sales margins, including
transactions with affiliates, were as follows:
- --------------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- --------------------------------------------------------------------------------------------------------------------------
Gas distribution operating revenue $102.5 $125.0 $(22.5) (18.0%) $343.5 $510.5 $(167.0) (32.7%)
Less: Gas purchased for resale 60.9 88.1 (27.2) (30.9%) 201.0 367.7 (166.7) (45.3%)
- ------------------------------------------------------------------- ---------------------------------
Margin $41.6 $36.9 $4.7 12.7% $142.5 $142.8 $(0.3) (0.2%)
==========================================================================================================================
Second Quarter 2002 vs 2001
Margin increased primarily due to customer growth. Revenues and gas
purchases decreased as a result of lower commodity natural gas prices.
Year to Date 2002 vs 2001
Margin decreased primarily due to milder weather and weak economic
conditions in the first quarter, which were partially offset by customer growth
in the second quarter. Revenues and gas purchases decreased as a result of lower
commodity natural gas prices.
Gas Transmission
Gas Transmission is comprised of the operations of South Carolina
Pipeline Corporation. Changes in the gas transmission sales margins, including
transactions with affiliates, were as follows:
- --------------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- --------------------------------------------------------------------------------------------------------------------------
Gas distribution operating revenue $110.9 $97.1 $13.8 14.2% $239.0 $298.4 $(59.4) (19.9%)
Less: Gas purchased for resale 98.4 86.5 11.9 13.8% 227.0 278.7 (51.7) (18.6%)
- ------------------------------------------------------------------- ---------------------------------
Margin $12.5 $10.6 $1.9 17.9% $12.0 $19.7 $(7.7) (39.1%)
==========================================================================================================================
Second Quarter 2002 vs 2001
Margin increased primarily due to the favorable competitive position of
natural gas relative to alternate fuels, including increased sales for electric
generation.
Year to Date 2002 vs 2001
Margin decreased primarily due to the unfavorable competitive position
of natural gas relative to alternate fuels in the first quarter, which was
partially offset by a favorable competitive position in the second quarter.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in Georgia's deregulated natural gas
market. Retail Gas Marketing also includes industrial sales in the state of
Georgia. Retail gas marketing revenues and net income, were as follows:
- ----------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ----------------------------------------------------------------------------------------------------------
Operating revenues $111.2 $121.0 $(9.8) (8.1%) $296.2 $384.0 $(87.8) (22.9%)
Net income (loss) $0.7 $(2.5) $3.2 * $14.6 $6.8 $7.8 *
==========================================================================================================
*Greater than 100%
Second Quarter 2002 vs 2001
Operating revenues decreased primarily as a result of the decline in
commodity natural gas prices, lower volumes and fewer customers. The change from
a net loss in 2001 to net income in 2002 resulted primarily from lower bad debt
expense.
Year to Date 2002 vs 2001
Operating revenues decreased primarily as a result of the decline in
commodity natural gas prices, lower volumes and fewer customers. Net income
increased primarily due to lower bad debt expense.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Changes in energy marketing operating
revenues, including transactions with affiliates, and net income (loss) were as
follows:
- ------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ------------------------------------------------------------------------------------------------------
Operating revenues $33.4 $103.9 $(70.5) (67.9%) $72.4 $351.6 $(279.2) (79.4%)
Net income (loss) $(2.1) $1.6 $(3.7) * $(3.2) $5.1 $(8.3) *
======================================================================================================
*Greater than 100%
Second Quarter 2002 vs 2001
Operating revenue decreased primarily as a result of declines in
commodity natural gas prices from the record levels experienced in 2001 and due
to less favorable weather than in 2001. Net income (loss) decreased primarily as
a result of the closing of operations of SCANA Energy Trading, LLC during the
first quarter of 2002 and the closing of the Midwest office in the third quarter
of 2001.
Year to Date 2002 vs 2001
Operating revenues decreased primarily as a result of declines in
commodity natural gas prices from the record levels experienced in 2001 and due
to less favorable weather than in 2001. Net income (loss) decreased primarily as
a result of the closing of operations of SCANA Energy Trading, LLC during the
first quarter of 2002 and the closing of the Midwest office in the third quarter
of 2001.
Other Operating Expenses
Changes in other operating expenses were as follows:
- -----------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- -----------------------------------------------------------------------------------------------------------------
Other operation and maintenance $131.4 $122.0 $9.4 7.7% $257.8 $251.3 $6.5 2.6%
Depreciation and amortization 54.7 56.2 (1.5) (2.7%) 108.4 111.8 (3.4) (3.0%)
Other taxes 32.1 28.8 3.3 11.5% 63.3 58.7 4.6 7.8%
- ------------------------------------------------------------ -------------------------------
Total $218.2 $207.0 $11.2 5.4% $429.5 $421.8 $7.7 1.8%
=================================================================================================================
Other operation and maintenance expense for the three and six months
ended June 30, 2002 compared to the corresponding periods in 2001 increased
primarily due to increased nuclear refueling maintenance costs, higher property
insurance costs and reduced pension income in 2002. Depreciation and
amortization for the three and six months decreased due to implementation of
SFAS 142 and the resulting reduction in amortization expense related to goodwill
(see Note 1B of Notes to Condensed Consolidated Financial Statements), which was
partially offset by increases for normal property additions. Other taxes
increased primarily due to increased property taxes.
Other Income (Loss)
Other income, including AFC, for the three and six months ended June 30,
2002 increased compared to the corresponding periods in 2001 primarily due to
construction at the Urquhart Station, Jasper County and Lake Murray Dam
projects. The decrease in Other Income related to gain on sale of investments
and assets and the loss incurred from impairment of investments are discussed at
Earnings (Loss) Per Share.
Interest Expense
Interest expense for the three and six months ended June 30, 2002
decreased compared to the corresponding periods in 2001 primarily due to
declining interest rates on the Company's debt.
Income Taxes
Income taxes for the three and six months ended June 30, 2002 decreased
approximately $191 million and $283 million, respectively, when compared to the
corresponding periods in 2001. These decreases are primarily due to reductions
of deferred income taxes in connection with the non-recurring investment
impairments recorded in March and June 2002 arising from the Company's
telecommunications investments (see Note 5 of Notes to Condensed Consolidated
Financial Statements), which were partially offset in March and April 2002 by
the sale of DTAG stock and the sale of the Company's radio service network.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held
for purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
As of June 30, 2002 Expected Maturity Date
- ------------------- ----------------------
Millions of dollars
There- Fair
Liabilities 2002 2003 2004 2005 2006 after Total Value
- ------------------------------------- -------- --------- ---------- ---------- ---------- ---------- ------------ ---------
- ------------------------------------- -------- --------- ---------- ---------- ---------- ---------- ------------ ---------
Long-Term Debt:
Fixed Rate ($) 11.7 298.7 187.1 182.1 162.8 2,174.6 3,017.0 3,026.4
Average Fixed Interest Rate 8.32 6.38 7.58 7.43 8.63 6.79 6.94
Variable Rate ($) 300.0 - 150.0 - - 450.0 447.7
-
Average Variable Interest Rate 4.06 - 2.54 - - 3.55
-
Interest Rate Swap:
Pay Variable/Receive Fixed ($) - - 12.9 - - 332.0 344.9
14.2
Average Pay Interest Rate - - 7.82 - - 2.62 2.81
Average Receive Interest Rate - - 10.00 - - 6.35
6.21
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 investments in the 11.875 percent senior
discount notes (due 2007) of a telecommunications company, the cost basis of
which is approximately $82.1 million. See additional discussion at Other Matters
- - Telecommunications Investments at Management's Discussion and Analysis of
Financial Condition and Results of Operations.
Commodity price risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.
As of June 30, 2002
Millions of dollars, except weighted average settlement price and strike price
Natural Gas Derivatives: Expected Maturity in 2002 Expected Maturity in 2003
- ------------------------- --------------------------------- --------------------------------
Settlement Contract Fair Settlement Contract Fair
Price (a) Amount Value Price (a) Amount Value
Futures Contracts:
Long($) 3.54 40.2 44.9 3.92 27.6 33.4
Short($) 3.40 2.8 2.6 3.90 1.0 0.9
Strike Contract Strike Contract
Price Amount Price Amount
(a) (a)
Options:
Purchased put (long)($) 3.50 16.1 - -
Sold put (short)($) 3.45 26.4 2.30 4.1
- ------------------------- ----------- --------------------- ----------- --------------------
(a) Weighted average
See Note 5 of Notes to Condensed Consolidated Financial Statements for
additional information.
The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of different types. Instruments
designated as cash flow hedges are used to hedge risks associated with fixed
price obligations in a volatile market and risks associated with price
differentials at different delivery locations. The basic types of financial
instruments utilized are exchange-traded instruments, such as NYMEX futures
contracts or options, and over-the-counter instruments such as swaps, which are
typically offered by energy and financial institutions.
Risk limits are established to control the level of market, credit,
liquidity and operational and administrative risks assumed by the Company. The
Company's Board of Directors has delegated the authority for setting market risk
limits to a Risk Management Committee. The Risk Management Committee provides
assurance to the Board of Directors with regard to compliance with risk
management policies and brings to the Board's attention any areas of concern.
Written policies define the physical and financial transactions that are
approved, as well as the authorization requirements and limits for transactions
that are allowed.
The NYMEX futures information above includes those financial positions of
both Energy Marketing and SCPC. The ultimate effects of the hedging activities
of SCPC are passed through to its customers through SCPC's weighted average cost
of gas calculation.
Equity price risk - Investments in telecommunications companies' equity
securities are carried at market value or, if market value is not readily
determinable, at cost. The Company's investments in such securities totaled
$217.1 million at June 30, 2002. A temporary decline in value of ten percent
would result in a $21.7 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. An other than temporary
decline in value of ten percent would result in a $21.7 million reduction in
fair value and a corresponding adjustment to net income, net of tax effect.
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)
- --------------------------------------------------------------------------------
June 30, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Assets
Utility Plant:
Electric $4,862 $4,563
Gas 432 425
Other 195 188
- --------------------------------------------------------------------------------
Total 5,489 5,176
Accumulated depreciation and amortization (1,899) (1,841)
- --------------------------------------------------------------------------------
Total 3,590 3,335
Construction work in progress 420 511
Nuclear fuel, net of accumulated amortization 50 45
- --------------------------------------------------------------------------------
Utility Plant, Net 4,060 3,891
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 24 24
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 63 78
Receivables 246 212
Receivables - affiliated companies 3 4
Inventories (at average cost):
Fuel 44 39
Materials and supplies 49 48
Emission allowances 13 13
Prepayments 21 6
- --------------------------------------------------------------------------------
Total Current Assets 439 400
- --------------------------------------------------------------------------------
Deferred Debits:
Environmental 21 24
Nuclear plant decommissioning fund 83 79
Pension asset, net 252 239
Due from affiliates - pension
and postretirement benefits 16 15
Other regulatory assets 202 193
Other 107 97
- --------------------------------------------------------------------------------
Total Deferred Debits 681 647
- --------------------------------------------------------------------------------
Total $5,204 $4,962
================================================================================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- -------------------------------------------------------------- -----------------
June 30, December 31,
Millions of dollars 2002 2001
- -------------------------------------------------------------- -----------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $1,768 $1,750
Preferred stock (Not subject to
purchase or sinking funds) 106 106
- -------------------------------------------------------------- -----------------
Total Stockholders' Investment 1,874 1,856
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 1,609 1,412
- -------------------------------------------------------------- -----------------
Total Capitalization 3,543 3,328
- -------------------------------------------------------------- -----------------
Current Liabilities:
Short-term borrowings 213 165
Current portion of long-term debt 25 28
Accounts payable 112 99
Accounts payable - affiliated companies 70 78
Customer deposits 21 19
Taxes accrued 21 80
Interest accrued 33 27
Dividends declared 40 42
Deferred income taxes, net 17 12
Other 9 8
- -------------------------------------------------------------- -----------------
Total Current Liabilities 561 558
- -------------------------------------------------------------- -----------------
Deferred Credits:
Deferred income taxes, net 605 599
Deferred investment tax credits 107 109
Reserve for nuclear plant decommissioning 83 79
Due to affiliates - pension and
postretirement benefits 17 16
Postretirement benefits 127 122
Regulatory liabilities 95 81
Other 66 70
- -------------------------------------------------------------- -----------------
Total Deferred Credits 1,100 1,076
- -------------------------------------------------------------- -----------------
Total $5,204 $4,962
============================================================== =================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- ---------------------------------------------------------------- ------------------------- --------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2002 2001 2002 2001
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Operating Revenues:
Electric $350 $342 $654 $683
Gas 53 58 160 215
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Total Operating Revenues 403 400 814 898
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Operating Expenses:
Fuel used in electric generation 75 55 131 105
Purchased power (including affiliated purchases) 42 61 75 136
Gas purchased for resale 40 46 112 165
Other operation and maintenance 97 84 180 162
Depreciation and amortization 42 41 84 82
Other taxes 28 25 54 50
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Total Operating Expenses 324 312 636 700
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Operating Income 79 88 178 198
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Other Income:
Other Income, Including Allowance for Equity Funds
Used During Construction 10 9 19 13
Gain on sale of assets - 1 - 1
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Total Other Income 10 10 19 14
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 89 98 197 212
Interest Charges, Net of Allowance for Borrowed
Funds Used During Construction 29 28 57 56
Preferred Dividend Requirement of the Company -
Obligated Mandatorily Redeemable Preferred Securities 1 1 2 2
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Income Before Income Taxes and Preferred Stock Dividends 59 69 138 154
Income Taxes 19 26 46 57
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Net Income 40 43 92 97
Preferred Stock Cash Dividends Declared (At stated rates) 2 2 4 4
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------
Earnings Available for Common Stockholder $38 $41 $88 $93
================================================================ ============ ============ ============= ============
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $92 $97
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 84 82
Amortization of nuclear fuel 7 6
Allowance for funds used during construction (18) (7)
Gain on sale of assets - (1)
Over (under) collections, fuel adjustment clauses (11) (11)
Changes in certain assets and liabilities:
(Increase) decrease in receivables (33) 31
(Increase) decrease in inventories (6) (9)
(Increase) decrease pension asset (13) (20)
(Increase) decrease other regulatory assets 2 2
Increase (decrease) deferred income taxes, net 11 19
Increase (decrease) other regulatory liabilitie 18 9
Increase (decrease) postretirement benefits 5 4
Increase (decrease) in accounts payable 5 (51)
Increase (decrease) in taxes accrued (59) (14)
Increase (decrease in interest accrued 6 6
Other, net (25) (32)
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 65 111
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (238) (151)
Proceeds from sales of assets 1 1
Nonutility property additions (1) -
Investments (3) -
- --------------------------------------------------------------------------------
Net Cash Used For Investing Activities (241) (150)
- --------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149
Capital contribution from parent 3 15
Repayments:
First and Refunding Mortgage Bonds (104) -
Other long-term debt (2) (2)
Dividends and distributions:
Common stock (75) (77)
Preferred stock (4) (4)
Short-term borrowings, net 48 (72)
- --------------------------------------------------------------------------------
Net Cash Provided From Financing Activities 161 9
- --------------------------------------------------------------------------------
Net Decrease In Cash and Temporary Investments (15) (30)
Cash and Temporary Investments, January 1 78 60
- --------------------------------------------------------------------------------
Cash and Temporary Investments, June 30 $63 $30
================================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $7 for 2002 and $4 for 2001) $84 $77
- Income taxes $45 11
See Notes to Condensed Consolidated Financial Statements.
50
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2002
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in South Carolina Electric & Gas
Company's (the Company) Annual Report on Form 10-K for the year ended December
31, 2001. These are interim financial statements, and due to the seasonality of
the Company's business, the amounts reported in the Condensed Consolidated
Statements of Income are not necessarily indicative of amounts expected for the
year. In the opinion of management, the information furnished herein reflects
all adjustments, all of a normal recurring nature which are necessary for a fair
statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result, the Company has
recorded as of June 30, 2002 approximately $223 million and $95 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets, and liabilities of approximately $125 million and
$86 million, respectively. The electric and gas regulatory assets of
approximately $56 million and $41 million, respectively, (excluding deferred
income tax assets) are recoverable through rates. The Public Service Commission
of South Carolina (SCPSC) has reviewed and approved most of the items shown as
regulatory assets through specific orders. Other items represent costs which are
not yet approved for recovery by the SCPSC, but are the subject of current or
future filings. In recording these costs as regulatory assets, management
believes the costs will be allowable under existing rate-making concepts that
are embodied in current rate orders received by the Company. However, ultimate
recovery is subject to SCPSC approval. In the future, as a result of
deregulation or other changes in the regulatory environment, the Company may no
longer meet the criteria for continued application of SFAS 71 and could be
required to write off its regulatory assets and liabilities. Such an event could
have a material adverse effect on the Company's results of operations in the
period the write-off would be recorded, but it is not expected that cash flows
or financial position would be materially affected.
B. New Accounting Standards
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing liabilities related to the future
obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective
January 1, 2003. The impact SFAS 143 may have on the Company's financial
position has not been determined but could be material. Because any ARO
anticipated to be recorded would relate to regulated operations, it is not
expected that the adoption of the statement will have any impact on results of
operations or cash flows.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" became effective January 1, 2002. This statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
SFAS 145, "Rescission of SFASs 4, 44 and 64, Amendment of SFAS 13, and
Technical Corrections," was issued in April 2002. The provisions of SFAS 145,
among other things, discontinue treating gains or losses from the early
extinguishment of debt as extraordinary items unless such early extinguishment
meets the criteria of Accounting Principles Board Opinion No. 30. The Company
will adopt SFAS 145 effective January 1, 2003 and does not expect that such
adoption will have any impact on the Company's results of operations, cash flows
or financial position.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. This statement requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that such adoption will have any impact on the Company's results of operations,
cash flows or financial position.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
Electric
In April 2002 the SCPSC approved the Company's request to increase the
fuel component of rates charged to electric customers from 1.579 cents per
kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2002 through April 2003. The increase
also provides recovery for under-collected actual fuel costs through April 2002,
including short-term purchased power costs necessitated by outages at two of the
Company's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002.
In September 1999 the SCPSC 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 SCPSC 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 SCPSC. Any unused portion of the $36 million in any given year
may be carried forward for possible use in the following year. As of June 30,
2002 no accelerated depreciation has been recorded. The accelerated capital
recovery plan will be accomplished through existing customer rates.
Gas
The Company's rates are established using a cost of gas component
approved by the SCPSC which may be modified periodically to reflect changes in
the price of natural gas purchased by the Company.
The Company's cost of gas component in effect during the period January
1, 2001 through June 30, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-June 2002
In 1994 the SCPSC issued an order approving the Company's request to
recover, through a billing surcharge to its gas customers, the costs of
environmental cleanup at the sites of former manufactured gas plants (MGPs). The
billing surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for the Company's gas operations that had
previously been deferred. In October 2001, as a result of the annual review, the
SCPSC 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 June 30, 2002 ($20.6 million) prior to the
end of 2005.
3. LONG-TERM DEBT
On January 31, 2002 the Company issued $300 million of first mortgage
bonds having an annual interest rate of 6.625 percent and maturing February 1,
2032. The proceeds from the sale of these bonds were used to reduce short-term
debt primarily incurred as a result of the Company's construction program and to
redeem on March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent
Series due August 15, 2021.
4. 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
June 30, 2002 approximately $39 million of retained earnings were restricted by
this requirement as to payment of cash dividends on common stock.
5. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 12 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001. Commitments and Contingencies at June 30, 2002 include
the following:
A. Lake Murray Dam Reinforcement
In 1999 the Federal Energy Regulatory Commission (FERC) mandated that
the Company reinforce its Lake Murray dam in order to maintain the lake in case
of an extreme earthquake. Construction for the project and related activities,
which began in the third quarter of 2001, is expected to cost approximately $250
million and be completed in 2005.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public
liability for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 million of the liability per reactor would be
assessed per year. The Company's maximum assessment, based on its two-thirds
ownership of 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
Santee Cooper) with Nuclear Electric Insurance Limited. The policies, covering
the nuclear facility for property damage, excess property damage and outage
costs, permit assessments under certain conditions to cover insurer's losses.
Based on the current annual premium, the Company's portion of the retrospective
premium assessment would not exceed $15.5 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and expenses arising
from a nuclear incident at Summer Station exceed the policy limits of insurance,
or to the extent such insurance becomes unavailable in the future, and to the
extent that the Company's rates would not recover the cost of any purchased
replacement power, the Company will retain the risk of loss as a self-insurer.
The Company has no reason to anticipate a serious nuclear incident at Summer
Station. If such an incident were to occur, it would have a material adverse
impact on the Company's results of operations, cash flows and financial
position.
C. Environmental
The Company maintains an environmental assessment program to identify
and evaluate current and former operations sites that could require
environmental cleanup. As site assessments are initiated, estimates are made of
the amount of expenditures, if any, deemed necessary to investigate and clean up
each site. These estimates are refined as additional information becomes
available; therefore, actual expenditures could differ significantly from the
original estimates. Amounts estimated and accrued to date for site assessments
and cleanup relate primarily to regulated operations.
Such amounts are deferred and amortized with recovery provided through
rates. Deferred amounts, net of amounts previously recovered through rates and
insurance settlements, totaled $20.6 million at June 30, 2002. The deferral
includes the estimated costs associated with the following matters.
In September 1992 the Environmental Protection Agency (EPA) notified the
Company, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of the Company's decommissioned
MGPs. Field work at the site began in November 1993 and has required the
submission of several investigative reports and the implementation of several
work plans. In September 2000, the Company was notified by the South Carolina
Department of Health and Environmental Control (DHEC) that benzene contamination
was detected in the intermediate aquifer on surrounding properties of the
Calhoun Park area site. The EPA required that the Company conduct a focused
Remedial Investigation/Feasibility Study on the intermediate aquifer, which was
completed in June 2001. The EPA expects to issue a Record of Decision dealing
with the intermediate aquifer and sediments in late 2002. The Company
anticipates that major remediation activities will be completed in 2003, with
certain monitoring activities continuing until 2007. As of June 30, 2002, the
Company has spent approximately $17.9 million to remediate the Calhoun Park area
site. Total remediation costs are estimated to be $21.9 million.
The Company owns three other decommissioned MGP sites in South Carolina
which contain residues of by-product chemicals. Two of these sites are currently
being remediated under work plans approved by DHEC. The Company is continuing to
investigate the remaining site and is monitoring the nature and extent of
residual contamination. The Company anticipates that major remediation
activities for these three sites will be completed before 2006. The Company has
spent approximately $2.0 million related to these sites and expects to spend an
additional $6.0 million.
6. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The
Company uses operating income to measure profitability for its 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.
The Electric Operations segment is comprised of the electric portion of
the Company and South Carolina Fuel Company (Fuel Company)and is primarily
engaged in the generation, transmission, and distribution of electricity. The
Company's electric service territory extends into 24 counties covering more than
15,000 square miles in the central, southern, and southwestern portions of South
Carolina. Sales of electricity to industrial, commercial, and residential
customers are regulated by the SCPSC and by FERC. Fuel Company acquires, owns,
and provides financing for the fuel and emission allowances required for the
operation of the Company's generation facilities.
The Gas Distribution segment, comprised of the Company's local
distribution operations, is engaged in the purchase and sale, primarily at
retail, of natural gas. The Company's operations extend to 33 counties in South
Carolina covering approximately 22,000 square miles.
The Company's reportable segments share a similar regulatory environment
and, in some cases, overlapping service areas. However, Electric Operations'
product differs from Gas Distribution's, as does the generation process and
method of distribution.
Disclosure of Reportable Segments
(Millions of Dollars)
- ------------------------------------- -------------- ---------------- ---------
Three months ended External Intersegment Operating Segment
June 30, 2002 Revenue Revenue Income (Loss) Assets
- ------------------------------------- -------------- ---------------- ---------
Electric Operations $350 $55 $83 $5,245
Gas Distribution 53 1 (4) 435
All Other - - - 4
Adjustments/Eliminations - (56) - (480)
- ------------------------------------- -------------- ---------------- ---------
- ------------------------------------- -------------- ---------------- ---------
Consolidated Total $403 - $79 $5,204
===================================== ============== ================ =========
- -------------------------------- --------------- ---------------- -----------
Six months ended External Intersegment Operating Segment
June 30, 2002 Revenue Revenue Income (Loss) Assets
- -------------------------------- --------------- ---------------- -----------
Electric Operations $654 $107 $167 $5,245
Gas Distribution 160 1 12 435
All Other - - - 4
Adjustments/Eliminations - (108) (1) (480)
- ----------------------------------- --------------- ---------------- -----------
- ----------------------------------- --------------- ---------------- -----------
Consolidated Total $814 - $178 $5,204
=================================== =============== ================ ===========
- ---------------------------------- ------------- ----------------- -----------
Three months ended External Intersegment Operating Segment
June 30, 2001 Revenue Revenue Income (Loss) Assets
- ---------------------------------- ------------- ----------------- -----------
Electric Operations $342 $52 $94 $4,790
Gas Distribution 58 - (5) 423
All Other - - -
5
Adjustments/Eliminations - (52) (1)
(457)
- ----------------------------------- ------------- ----------------- -----------
- ----------------------------------- ------------- ----------------- -----------
Consolidated Total $ 400 - $88 $4,761
=================================== ============= ================= ===========
- --------------------------------- --------------- ---------------- -----------
Six months ended External Intersegment Operating Segment
June 30, 2001 Revenue Revenue Income (Loss) Assets
- --------------------------------- --------------- ---------------- -----------
Electric Operations $683 $99 $184 $4,790
Gas Distribution 215 - 16 423
All Other - - -
5
Adjustments/Eliminations - (99) (2)
(457)
- ---------------------------------- --------------- ---------------- -----------
Consolidated Total $898 - $198 $4,761
================================== =============== ================ ===========
7. SUBSEQUENT EVENTS
A. On August 2, 2002 the Company filed a registration statement with the
Securities and Exchange Commission for the proposed issuance and sale of up to
6,000,000 shares of SCANA Common Stock. The offering is expected to be concluded
in fall of 2002. Net proceeds from the sale will be contributed to the equity
capital of SCE&G or used for general corporate purposes.
B. On August 6, 2002 SCE&G filed an application with the SCPSC requesting a $105
million increase in retail electric revenues. The electric rate request is
largely associated with the power generation projects at SCE&G's recently
completed Urquhart Station and the generating station currently under
construction in Jasper County. It also includes costs for equipment required for
environmental and air quality improvements.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- -------------------------------------------------------------------------------
SOUTH CAROLINA ELECTRIC & GAS COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations
appearing in South Carolina Electric & Gas Company's (SCE&G) Annual Report on
Form 10-K for the year ended December 31, 2001.
Statements included in this discussion and analysis (or elsewhere in this
quarterly report) which are not statements of historical fact are intended to
be, and are hereby identified as, "forward-looking statements" for purposes of
the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, (3) changes in the economy, especially in SCE&G's service
territory, (4) the impact of competition from other energy suppliers, (5) growth
opportunities, (6) the results of financing efforts, (7) changes in SCE&G's
accounting policies, (8) weather conditions, especially in areas served by
SCE&G, (9) 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 SEC. SCE&G disclaims any obligation to update any
forward-looking statements.
COMPETITION
In South Carolina electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2002.
Further, while several companies have announced their intent to site merchant
generating plants in SCE&G's service territory, economic events, environmental
concerns and other factors have slowed those efforts. At the Federal level,
energy legislation has passed both houses of Congress in 2002, though
significant differences exist between the House and Senate versions. Among other
things, this legislation would require that one percent of the electric energy
sold by retail electric suppliers be generated from renewable energy resources
beginning in 2005. This requirement would gradually escalate to ten percent in
2019. Substantial penalties would be levied for failure to comply. Electric
cooperatives and municipal utilities would be exempt from these requirements. In
addition, on July 31, 2002, FERC proposed new rules aimed at creating a standard
market design for wholesale electric markets. See Other Matters-Regional
Transmission Organization, in this Management's Discussion and Analysis of
Financial Condition and Results of Operations. SCE&G is not able to predict
whether these or similar legislative or regulatory actions will be enacted and,
if they are, the impact they will have on SCE&G.
LIQUIDITY AND CAPITAL RESOURCES
SCE&G's cash requirements arise primarily from its operational needs,
funding its construction program and payment of dividends to SCANA. The ability
of SCE&G to replace existing plant investment, as well as to expand to meet
future demand for electricity and gas, will depend upon its ability to attract
the necessary financial capital on reasonable terms. SCE&G recovers the costs of
providing services through rates charged to customers. Rates for regulated
services are generally based on historical costs. As customer growth and
inflation occur and SCE&G continues its ongoing construction program, SCE&G
expects to seek increases in rates. SCE&G's future financial position and
results of operations will be affected by its ability to obtain adequate and
timely rate and other regulatory relief, if requested.
On August 6, 2002 SCE&G filed an application with the Public Service
Commission of South Carolina (SCPSC) requesting a $104.7 million increase in
retail electric revenues. The electric rate request is largely associated with
the power generation projects at SCE&G's recently completed Urquhart Station and
the Jasper Generating Station currently under construction, both of which are
discussed below. It also includes costs for equipment required for environmental
and air quality improvements.
The following table summarizes how SCE&G generated and used funds for
property additions and construction expenditures during the six months ended
June 30, 2002 and 2001:
- --------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2002 2001
- ------------------------------------------------------------------- ------------
Net cash provided from operating activities $65 $111
Net cash provided from for financing activities 161 9
Cash and temporary cash investments
available at the beginning of the period 78 60
- ------------------------------------------------------------------- ------------
Net cash available for utility property
additions and construction expenditures $304 $180
=================================================================== ============
Funds used for utility property additions
and construction expenditures, net of
noncash allowance for funds used during construction $238 $151
=================================================================== ============
SCE&G anticipates that the remainder of its 2002 cash requirements will
be met through internally generated funds, the incurrence of additional
short-term and long-term indebtedness and a capital contribution from SCANA
Corporation. See Note 7A of Notes to Condensed Consolidated Financial
Statements. SCE&G expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the next 12 months and for
the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12
months ended June 30, 2002 was 3.54.
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem on
March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent Series due
August 15, 2021.
SCE&G placed in service a $248 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 340 megawatts of new electric generation and use exhaust
heat to replace coal-fired steam that powers two existing 75 megawatt turbines
at the Urquhart Generating Station.
In 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order
to maintain the lake in case of an extreme earthquake. Construction for the
project and related activities, which began in the third quarter of 2001, is
expected to cost approximately $250 million and be completed in 2005.
In May 2002 SCE&G began construction of an 875 megawatt generation
facility in Jasper County, South Carolina, to supply electricity to its South
Carolina customers. The facility will include three natural gas
combustion-turbine generators and one steam-turbine generator. The $450 million
facility is expected to begin commercial operation in the summer of 2004, and
SCG Pipeline, Inc., an affiliate, will transport natural gas to the facility. In
connection with the facility, SCE&G has signed a 250 megawatt electric supply
contract with North Carolina Electric Membership Corporation for a term of at
least nine years beginning January 1, 2004.
SECURITIES RATINGS (As of July 31, 2002)
- -------------------------------------------------------------------------------
First and
First Refunding Trust
Rating Mortgage Mortgage Preferred Preferred Commercial
Agency Bonds Bonds Stock Securities Paper
Moody's A1 A1 Baa1 A3 P-1
Standard & Poor's A- A- BBB BBB A-1
Fitch Ratings A+ A+ A A F-1
- -------------------------------------------------------------------------------
These ratings reflect the downgrade issued by Standard & Poor's on July
31, 2002. The Company does not expect the downgrade to adversely impact the
Company's liquidity.
Environmental Matters
For information on environmental matters see Note 5C of Notes To
Condensed Consolidated Financial Statements.
Other Matters
Regional Transmission Organization (RTO)
In June 2002 the Company and the other two electric utilities that
formed GridSouth Transco LLC (GridSouth) suspended implementation of GridSouth.
Though the three companies continue to support the RTO concept, GridSouth
implementation was suspended pending the issuance and evaluation of new FERC
directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR)
which further defines FERC's new standard market design for wholesale electric
markets, including bidding rules and other measures to create a common market
framework. The Company is currently evaluating this NOPR to determine what
effect it will have on the Company's operations. Additional directives from FERC
are expected later in 2002.
Transit
SCE&G and the City of Columbia, South Carolina (City) have entered into
an agreement under which a regional transit authority is expected to take over
operation of SCE&G's transit system effective August 31, 2002. As part of the
agreement, SCE&G will pay the City $32 million over seven years in exchange for
a 30-year electric and gas franchise, will convey transit-related property and
equipment to the City and will convey the historic Columbia Canal and
Hydroelectric Plant to the City. The transaction has been approved by the SCPSC
and the SEC, but is still subject to approval by FERC and other customary
conditions to closing.
Nuclear Station License Extension
In August 2002 SCE&G filed an application with the Nuclear Regulatory
Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear
Station (Summer Station). If approved, the extension would allow the plant to
operate through 2042.
RESULTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2002
AS COMPARED TO THE CORRESPONDING PERIOD IN 2001
Net Income
Net income for the second quarter and year to date periods ended June
30, 2002 and 2001 was as follows:
- -------------------------------------------------------- -----------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- ----------------------------- ------- -------------- ------ --------------------
Net income $39.4 $43.0 $(3.6) (8.4%) $91.4 $96.5 $(5.1) (5.3%)
- ----------------------------- ------- -------------- ------ -------------- ----
Second Quarter 2002 vs 2001
Net income decreased primarily due to higher operation and maintenance
expenses and lower pension income, which were partially offset by increased
electric margins.
Year to Date 2002 vs 2001
Net income decreased primarily due to higher operation and maintenance
expenses, lower pension income and lower electric and gas margins in the first
quarter, which were partially offset by higher electric margins in the second
quarter.
Pension Income
For the last several years, the market value of the Company's retirement
plan (pension) assets has exceeded the total actuarial present value of
accumulated plan benefits. Pension income in the second quarter and the year to
date periods of 2002 decreased significantly compared to corresponding periods
in 2001 primarily as a result of a less favorable investment market. Pension
income during these periods was recorded on the Company's financial statements
as follows:
- --------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 2002 2001
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Financial Statement Impact:
Reduction in employee benefit costs $3.1 $4.8 $6.6 $9.6
Increase in other income 1.9 3.0 3.9 6.0
Reduction in capital expenditures 1.0 1.4 1.9 2.8
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Total Pension Income $6.0 $9.2 $12.4 $18.4
===============================================================================
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of
both equity and borrowed funds used to finance construction (which is shown on
the balance sheet as construction work in progress) is capitalized. Both the
equity and the debt portions of AFC are noncash items of nonoperating income
which have the effect of increasing reported net income. AFC represented
approximately 15 percent and 13 percent of income before income taxes for the
three and six months ended June 30, 2002, respectively. AFC represented
approximately six percent and five percent of income before income taxes and
preferred stock dividends for the three and six months ended June 30, 2001. The
increase in AFC for the three and six months ended June 30, 2002 compared to the
corresponding periods in 2001, is primarily the result of increased construction
expenditures related to the projects at Urquhart Station, Jasper County and Lake
Murray Dam (see discussion at LIQUIDITY AND CAPITAL RESOURCES).
Dividends Declared
SCE&G's Board of Directors declared the following dividends on common
stock held by SCANA during 2002:
-------------------- ------------------ -------------------- -----------------
Declaration Date Dividend Amount Quarter Ended Payment Date
-------------------- ------------------ -------------------- -----------------
February 21, 2002 $34.0 million March 31, 2002 April 1, 2002
May 2, 2002 $38.0 million June 30, 2002 July 1, 2002
August 1, 2002 $40.5 million September 30, 2002 October 1, 2002
-------------------- ------------------ -------------------- -----------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and
South Carolina Fuel Company. Changes in the electric operations sales margins
were as follows:
----------------------------------- -------------------------------------- -----------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
----------------------------------- -------- --------- ------------------- --------- --------- ---------------------
Electric operating revenue $349.6 $341.8 $7.8 2.3% $653.9 $683.4 $(29.5) (4.3%)
Less: Fuel used in generation 75.2 54.7 20.5 37.5% 130.7 104.7 26.0 24.8%
Purchased power 42.1 61.3 (19.2) (31.3%) 75.0 135.9 (60.9) (44.8%)
----------------------------------- -------- --------- --------- ----------
-------- ---------
Margin $232.3 $225.8 $6.5 2.9% $448.2 $442.8 $5.4 1.2%
=================================== ======== ========= ======== ========== ========= ========= ========== ==========
Second Quarter 2002 vs 2001
Margin increased due to more favorable weather. Fuel used in generation
increased and purchased power cost decreased due to the repowering project at
the Urquhart plant which was completed in June 2002 and higher utilization of
steam plants during the planned maintenance outage at Summer Station in 2002.
Year to Date 2002 vs 2001
Margin increased due to more favorable weather in the second quarter,
which was partially offset by less favorable weather in the first quarter. Fuel
used in generation increased and purchased power cost decreased due to more
plants being on line during the period.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Changes in the gas distribution sales margins were as follows:
----------------------------------- ------------------------------------- ------------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
----------------------------------- ------- --------- ------------------- --------- --------- ----------------------
Gas operating revenue $53.0 $57.8 $(4.8) (8.3%) $160.1 $214.9 $(54.8) (25.5%)
Less: Gas purchased for resale 39.6 46.5 (6.9) (14.8%) 112.3 165.4 (53.1) (32.1%)
----------------------------------- -------- --------- --------- -----------
------- ---------
Margin $13.4 $11.3 $2.1 18.6% $47.8 $49.5 (1.7) (3.4%)
=================================== ======= ========= ======== ========== ========= ========= =========== ==========
Second Quarter 2002 vs 2001
Margin increased primarily due to customer growth. Revenues and gas
purchases decreased as a result of lower commodity natural gas prices.
Year to Date 2002 vs 2001
Margin decreased primarily due to milder weather and weak economic
conditions in the first quarter, which was partially offset by customer growth
in the second quarter. Revenues and gas purchases decreased as a result of lower
commodity natural gas prices.
Other Operating Expenses
Changes in other operating expenses were as follows:
- -------------------------------------- --------------------------------------- ----------------------------------------
Second Quarter Year to Date
Millions of dollars 2002 2001 Change 2002 2001 Change
- -------------------------------------- ---------- --------- ------------------ --------- --------- --------------------
Other operation and maintenance $96.8 $83.7 $13.1 15.7% $179.6 $162.6 $17.0 10.5%
Depreciation and amortization 42.5 41.0 1.5 3.7% 84.0 81.6 2.4 2.9%
Other taxes 27.8 24.8 3.0 12.1% 54.3 50.4 3.9 7.7%
- -------------------------------------- ------- --------- --------- ---------
---------- ---------
Total $167.1 $149.5 $17.6 11.8% $317.9 $294.6 $23.3 7.9%
====================================== ========== ========= ======= ========== ========= ========= ========= ==========
Other operating expenses for the three and six months ended June 30,
2002 increased primarily as a result of increased nuclear refueling maintenance
costs, reduced pension income in 2002 and higher property insurance costs. The
increase in depreciation and amortization expenses for the three months ended
June 30, 2002 resulted primarily from normal property additions. Other taxes
increased primarily as a result of increased property taxes.
Other Income
Other income for the six months ended June 30, 2002 increased when
compared to the corresponding periods in 2001, primarily as a result of the
increase in the equity component of AFC (see AFC discussion at Earnings and
Dividends).
Income Taxes
Income taxes for the three and six months ended June 30, 2002 decreased
when compared to the corresponding period in 2001, primarily as a result of the
change in operating income. In addition, the equity component of AFC is not
taxable; therefore the higher AFC discussed previously did not result in a
corresponding increase in income taxes.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates.
As of June 30, 2002
Millions of dollars Expected Maturity Date
There- Fair
Liabilities 2002 2003 2004 2005 2006 after Total Value
- ----------------------------- -------- ------- --------------------------------- ----------
- ----------------------------- -------- ------- --------------------------------- ----------
Long-Term Debt:
Fixed Rate ($) 1.6 129.7 123.9 173.9 154.6 1,147.8 1,731.5 1,716.8
Average Interest Rate 6.50 6.37 7.52 7.40 8.66 6.91 7.12
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)
- ------------------------------------------------------------- ------------------
June 30, December 31,
Millions of dollars 2002 2001
- ------------------------------------------------------------- ------------------
Assets
Gas Utility Plant $874 $855
Accumulated depreciation (302) (288)
Acquisition adjustment, net of
accumulated amortization 439 439
- ------------------------------------------------------------- ------------------
Gas Utility Plant, Net 1,011 1,006
- ------------------------------------------------------------- ------------------
Nonutility Property and Investments, Net 28 29
- ------------------------------------------------------------- ------------------
Current Assets:
Cash and temporary investments 44 18
Restricted cash and temporary investments 2 2
Receivables (net of allowance for
uncollectible accounts of $2
for 2002 and $1 for 2001) 23 70
Receivables - affiliated companies 16 12
Inventories (at average cost):
Stored gas 33 47
Materials and supplies 9 8
- ------------------------------------------------------------- ------------------
Total Current Assets 127 157
- ------------------------------------------------------------- ------------------
Deferred Debits:
Due from affiliate-pension asset 14 14
Regulatory assets 16 11
Other 5 4
- ------------------------------------------------------------- ------------------
Total Deferred Debits 35 29
- ------------------------------------------------------------- ------------------
Total $1,201 $1,221
============================================================= ==================
============================================================= ==================
Capitalization and Liabilities
Capitalization:
Common equity $725 $715
Long-term debt, net 291 290
- ------------------------------------------------------------- ------------------
Total Capitalization 1,016 1,005
- ------------------------------------------------------------- ------------------
Current Liabilities:
Current portion of long-term debt 4 4
Accounts payable 15 41
Accounts payable -affiliated companies 10 10
Customer prepayments and deposits 19 17
Taxes accrued 1 5
Dividends declared and interest accrued 10 6
Other 3 3
- ------------------------------------------------------------- ------------------
Total Current Liabilities 62 86
- ------------------------------------------------------------- ------------------
Deferred Credits:
Deferred income taxes, net 87 86
Deferred investment tax credits 2 2
Due to affiliate-postretirement benefits 15 14
Regulatory liabilities 4 14
Other 15 14
- ------------------------------------------------------------- ------------------
Total Deferred Credits 123 130
- ------------------------------------------------------------- ------------------
Total $1,201 $1,221
============================================================= ==================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2002 2001 2002 2001
-------------------------------------------------------------------- ----------------------------------
Operating Revenues $49 $67 $183 $295
Cost of Gas 21 41 88 202
-------------------------------------------------------------------- ----------------------------------
Gross Margin 28 26 95 93
-------------------------------------------------------------------- ----------------------------------
Operating Expenses:
Operation and maintenance 16 15 34 32
Depreciation and amortization 9 11 17 21
Other taxes 2 2 4 3
-------------------------------------------------------------------- ----------------------------------
Total Operating Expenses 27 28 55 56
-------------------------------------------------------------------- ----------------------------------
Operating Income (Loss) 1 (2) 40 37
----------------------------------------------------------------------------------------------------------
Other Income, including allowance for equity funds
used during construction 1 2 2 4
Interest Charges, net of allowance for borrowed funds
used during construction 5 5 11 11
-------------------------------------------------------------------- ----------------------------------
Income (Loss) Before Income Taxes (3) (5) 31 30
Income Tax Expense (Benefit) (1) - 12 14
-------------------------------------------------------------------- ----------------------------------
-------------------------------------------------------------------- ----------------------------------
Net Income (Loss) $(2) $(5) $19 $16
==================================================================== ==================================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $19 $16
Adjustments to reconcile net income to
net cash provided from operating activities:
Depreciation and amortization 19 22
Excess distributions (undistributed earnings) of investee - 3
Over (under) collection, fuel adjustment clause (15) 14
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 43 90
(Increase) decrease in inventories 13 (6)
Increase (decrease) in accounts payable and advances (26) (94)
Increase (decrease) in deferred income taxes, net 1 2
Increase (decrease) in accrued taxes (4) (2)
Other, net 4 (2)
- ------------------------------------------------------------------------- ------
Net Cash Provided From Operating Activities 54 43
- ------------------------------------------------------------------------- ------
Cash Flows From Investing Activities:
Construction expenditures (24) (29)
Nonutility and other - 1
- ------------------------------------------------------------------------- ------
Net Cash Used For Investing Activities (24) (28)
- ------------------------------------------------------------------------- ------
Cash Flows From Financing Activities:
Issuance of medium-term notes - 148
Repayment of short-term borrowings, net - (125)
Capital contributions from parent 1 3
Cash dividends (5) (10)
- --------------------------------------------------------------------------------
Net Cash Provided From (Used For) Financing Activities (4) 16
- --------------------------------------------------------------------------------
Net Increase In Cash and Temporary Investments 26 31
Cash and Temporary Investments, January 1 18 8
- --------------------------------------------------------------------------------
Cash and Temporary Investments, June 30 $44 $39
========================================================================= ======
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $0.5 for 2002 and $0.6 for 2001) $9 $6
- Income taxes 16 15
See Notes to Condensed Consolidated Financial Statements.
53
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2002
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in Public Service Company of North
Carolina, Incorporated's (the Company) Annual Report on Form 10-K for the year
ended December 31, 2001. These are interim financial statements, and due to the
seasonality of the Company's business, the amounts reported in the Condensed
Consolidated Statements of Income are not necessarily indicative of amounts
expected for the year. In the opinion of management, the information furnished
herein reflects all adjustments, all of a normal recurring nature which are
necessary for a fair statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result, the Company has
recorded as of June 30, 2002 approximately $16 million and $4 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax liabilities of approximately $0.3 million. The North
Carolina Utilities Commission (NCUC) has reviewed and approved most of the items
shown as regulatory assets through specific orders. Other items represent costs
which are not yet approved for recovery by the NCUC, but are the subject of
current or future filings. In recording these costs as regulatory assets,
management believes the costs will be allowable under existing rate-making
concepts that are embodied in current rate orders received by the Company. In
the future, as a result of deregulation or other changes in the regulatory
environment, the Company may no longer meet the criteria for continued
application of SFAS 71 and could be required to write off its regulatory assets
and liabilities. Such an event could have a material adverse effect on the
Company's results of operations in the period the write-off would be recorded,
but it is not expected that cash flows or financial position would be materially
affected.
B. New Accounting Standards
The Company adopted SFAS 141, "Business Combinations," and SFAS 142,
"Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141
requires all acquisitions to be accounted for utilizing the purchase method. The
Company considers the amounts categorized by the Federal Energy Regulatory
Commission (FERC) as "acquisition adjustments" to be goodwill as defined in SFAS
142 and ceased amortization of such amounts upon the adoption of SFAS 142. This
amortization is related to the acquisition adjustment of approximately $466
million carried on the books of the Company. The Company has no other intangible
assets subject to amortization as provided in SFAS 142.
If the Company had ceased amortization during all periods presented in
the condensed consolidated statements of operations, net income (loss) would
have been as follows:
Three Months Ended Six Months Ended
June 30, June 30,
(Millions of dollars, except per share amounts) 2002 2001 2002 2001
---- ---- ---- ----
Net Income (Loss) as Reported $(2) $(5) $19 $16
Amortization of Acquisition Adjustment 3 - 7
--- --- ---- - ---- -
-
Net Income (Loss) as Adjusted $(2) $(2) $19 $23
==== ==== === ===
SFAS 142 provides a six-month transitional period from the effective
date of adoption for the Company to perform an assessment of whether there is an
indication that goodwill is impaired. The Company's initial analyses indicated
that a write down of the acquisition adjustment associated with PSNC ranging
from $200 million to $250 million will be required. The final valuation analysis
will be completed by December 31, 2002, and any write-down resulting from the
analysis will be recorded as the cumulative effect of a change in accounting
principle.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing liabilities related to the future
obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective
January 1, 2003. The impact SFAS 143 may have on the Company's financial
position has not been determined but could be material. Because any ARO
anticipated to be recorded would relate to regulated operations, it is not
expected that the adoption of the statement will have any impact on results of
operations or cash flows.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," became effective January 1, 2002. This statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements for the initial
adoption of SFAS 144.
SFAS 145, "Rescission of SFASs 4, 44 and 64, Amendment of SFAS 13, and
Technical Corrections," was issued in April 2002. The provisions of SFAS 145,
among other things, discontinue treating gains or losses from the early
extinguishment of debt as extraordinary items unless such early extinguishment
meets the criteria of Accounting Principles Board Opinion No. 30. The Company
will adopt SFAS 145 effective January 1, 2003 and does not expect that such
adoption will have any impact on the Company's results of operations, cash flows
or financial position.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. This statement requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that such adoption will have any impact on the Company's results of operations,
cash flows or financial position.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
The Company's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas and changes in the rates charged by the
Company's pipeline transporters. The Company 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 NCUC reviews the Company's gas
purchasing practices annually.
The Company's benchmark cost of gas in effect during the period January
1, 2001 through June 30, 2002 was as follows:
Rate Per Therm Effective Date
$.690 January 2001
$.750 February-March 2001
$.650 April-August 2001
$.500 September-October 2001
$.350 November-December 2001
$.300 January 2002
$.215 February-June 2002
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from the Company's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved the
Company's requests for disbursement of up to $28.4 million from the Company's
expansion fund to extend natural gas service to Madison, Jackson and Swain
Counties, North Carolina. The Company estimates that the cost of this project
will be approximately $31.4 million. The Madison County portion of the project
was completed at a cost of approximately $5.8 million and customers began
receiving service in July 2001. Construction has begun in Jackson County, and
approximately $0.9 million in construction costs have been incurred through June
30, 2002.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of the Company. As specified in the NCUC order, the Company reduced its rates by
approximately $1million in each of August 2000 and August 2001, and agreed to a
moratorium on general rate cases until August 2005. General rate relief can be
obtained during this period to recover costs associated with material adverse
governmental actions and force majeure events.
3. FINANCIAL INSTRUMENTS
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires
the Company to recognize all derivative instruments as either assets or
liabilities in the statement of financial position and to measure those
instruments at fair value. SFAS 133 further provides that changes in fair value
of derivative instruments are either recognized in earnings or reported as other
comprehensive income, depending upon the intended use of the derivative and the
resulting designation. The impact on the Company of adopting SFAS 133 was not
material.
In December 2001 the Company entered into two interest rate swap
agreements to pay variable rates and receive fixed rate interest payments on a
combined notional amount of $44.9 million. These swaps were designated as fair
value hedges of the Company's $12.9 million, 10% senior debenture due 2004 and
$32.0 million, 8.75% senior debenture due 2012. At June 30, 2002 the fair value
of these swaps was $0.9 million.
The fair value of these interest rate swaps is reflected within other
deferred debits on the balance sheet. The corresponding hedged fair value change
of the debt is also recorded on the balance sheet. The receipts or payments
related to the interest rate swaps are credited or charged to interest expense
as incurred.
4. COMMITMENTS AND CONTINGENCIES
The Company owns, or has owned, all or portions of seven sites in North
Carolina on which manufactured gas plants (MGPs) were formerly operated.
Intrusive investigation (including drilling, sampling and analysis) has begun at
two sites, and the remaining sites have been evaluated using historical records
and observations of current site conditions. These evaluations have revealed
that MGP residuals are present or suspected at several of the sites. The Company
estimates the cost to remediate the sites to be between $11.3 million and $21.9
million. 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). At June 30, 2002 the Company has
recorded a liability and associated regulatory asset of $8.9 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 $1.2 million. Management believes that all costs incurred will
be recoverable through gas rates.
5. SEGMENT OF BUSINESS INFORMATION
Gas Distribution is the Company's only reportable segment. Gas
Distribution uses operating income to measure profitability. Intersegment
revenues between Gas Distribution and nonreportable segments were not
significant.
Disclosure of Reportable Segments
(Millions of Dollars)
- -----------------------------------------------------------------------
Three months ended External Operating Segment
June 30, 2002 Revenue Income Assets
- -----------------------------------------------------------------------
Gas Distribution $49 $1 $1,170
All Other - n/a 28
Adjustments/Eliminations - - 3
- -----------------------------------------------------------------------
- -----------------------------------------------------------------------
Consolidated Total $49 $1 $1,201
=======================================================================
- --------------------------------------------- -------------- -------------------
Six months ended External Operating Segment
June 30, 2002 Revenue Income Assets
- --------------------------------------------- -------------- -------------------
Gas Distribution $183 $40 $1,170
All Other - n/a 28
Adjustments/Eliminations - - 3
- --------------------------------------------- -------------- -------------------
Consolidated Total $183 $40 $1,201
============================================= ============== ===================
- --------------------------------------------- -------------- -------------------
Three months ende External Operating Segment
June 30, 2001 Revenue Loss Assets
- --------------------------------------------- -------------- -------------------
Gas Distribution $67 $(2) $1,179
All Other - n/a 29
Adjustments/Eliminations - - (26)
- --------------------------------------------- -------------- -------------------
- --------------------------------------------- -------------- -------------------
Consolidated Total $67 $(2) $1,182
============================================= ============== ===================
- -------------------------------------------- --------------- -------------------
Six months ended External Operating Segment
June 30, 2001 Revenue Income Assets
- -------------------------------------------- --------------- -------------------
Gas Distribution $295 $37 $1,179
All Other - n/a 29
Adjustments/Eliminations - - (26)
- -------------------------------------------- --------------- -------------------
Consolidated Total $295 $37 $1,182
============================================ =============== ===================
Item 2. Management's Narrative Analysis of Results of Operations.
---------------------------------------------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Narrative Analysis of Results of Operations appearing in Public Service Company
of North Carolina, Incorporated's (PSNC) Annual Report on Form 10-K for the year
ended December 31, 2001.
Statements included in this narrative analysis (or elsewhere in this
quarterly report) which are not statements of historical fact are intended to
be, and are hereby identified as, forward-looking statements for purposes of the
safe harbor provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties, and that actual
results could differ materially from those indicated by such forward-looking
statements. Important factors that could cause actual results to differ
materially from those indicated by such forward-looking statements include, but
are not limited to, the following: (1) that the information is of a preliminary
nature and may be subject to further and/or continuing review and adjustment,
(2) changes in the utility regulatory environment, (3) changes in the economy,
especially in PSNC's service territory, (4) the impact of competition from other
energy suppliers, (5) growth opportunities, (6) the results of financing
efforts, (7) changes in PSNC's accounting policies, (8) weather conditions,
especially in areas served by PSNC, (9) 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 SEC. PSNC disclaims any
obligation to update any forward-looking statements.
Net Income and Dividends
Net income for the six months ended June 30, 2002 and 2001 was as
follows:
Millions of dollars 2002 2001
- -------------------------------------------------------------------------------
Net income derived from continuing operations $19.2 $15.6
===============================================================================
The increase in net income from continuing operations reflects the
elimination of the amortization of the acquisition adjustment of $6.7 million
(see Note 1B of Notes to Condensed Consolidated Financial Statements). The
increase was also attributable to an increase in gas sales margin, partially
offset by higher operating expenses and reduced other income.
The nature of PSNC's business is seasonal. The quarters ending June 30
and September 30 are generally PSNC's least profitable quarters due to decreased
demand for natural gas related to lower space heating requirements.
PSNC's Board of Directors authorized payment of dividends on common
stock held by SCANA as follows:
- -------------------- ------------------ -------------------- ------------------
Declaration Date Dividend Amount Quarter Ended Payment Date
- -------------------- ------------------ -------------------- ------------------
- -------------------- ------------------ -------------------- ------------------
February 21, 2002 $5.0 million March 31, 2002 April 1, 2002
May 2, 2002 $4.0 million June 30, 2002 July 1, 2002
August 1, 2002 $5.5 million September 30, 2002 October 1, 2002
- -------------------- ------------------ -------------------- ------------------
Gas Distribution
Gas distribution sales margins for 2002 and 2001 were as follows:
Millions of dollars 2002 2001 Change % Change
------------------------------------------- ---------------------------------
Operating revenues $183.4 $295.6 $(112.2) (38.0%)
Less: Cost of gas 88.7 202.3 (113.6) (56.2%)
------------------------------------------- ------------
Gross margin $94.7 $93.3 $1.4 1.5%
=========================================== =================================
Gas distribution sales margin for the six months ended June 30, 2002
increased primarily due to increased residential customer growth and industrial
usage. The increase in margin was partially offset by lower other operating
revenues and the effects of a $1 million reduction in rates in August 2001
related to the acquisition of PSNC by SCANA.
Operation and Maintenance Expenses
The $1.6 million increase in operation and maintenance expenses from
2001 is primarily due to higher labor costs.
Depreciation Expense
Depreciation expense decreased due to the elimination of the
amortization of the acquisition adjustment in the amount of $6.7 million (see
Note 1B of Notes to Condensed Consolidated Financial Statements). The decrease
is partially offset by depreciation expense attributable to additions to plant.
Other Income
Other income decreased $1.7 million primarily due to reduced interest
income.
Capital Expansion Program and Liquidity Matters
PSNC's capital expansion program includes the construction of lines,
systems and facilities and the purchase of related equipment. PSNC's 2002
construction budget is approximately $41 million, compared to actual
construction expenditures for 2001 of $75.3 million. PSNC's ratio of earnings to
fixed charges for the 12 months ended June 30, 2002 was 2.5.
In December 2001 PSNC entered into two interest rate swap agreements to
pay variable rates and receive fixed rates on a combined notional amount of
$44.9 million. (See Note 3 of Notes to Condensed Consolidated Financial
Statements.)
SECURITIES RATINGS (As of July 31, 2002)
PSNC
- ---------------------------------------------------
- --------------------- -------------- --------------
Rating Senior Commercial
Agency Unsecured Paper
Moody's A2 P-1
Standard & Poor's A- A-1
Fitch Ratings n/a n/a
- --------------------- -------------- --------------
These ratings reflect the downgrade issued by Standard & Poor's on July
31, 2002. The Company does not expect the downgrade to adversely impact the
Company's liquidity.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
SCANA Corporation:
For information regarding legal proceedings see Notes 4 and 13 of Notes
To Consolidated Financial Statements appearing in the Company's Annual
Report on Form 10-K for the year ended December 31, 2001, and Note 2
and Note 6 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 Notes 3 and 12 of Notes
To Consolidated Financial Statements appearing in South Carolina
Electric & Gas Company's Annual Report on Form 10-K for the year ended
December 31, 2001, and Note 2 and Note 5 " 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 Notes 5 and 11 of Notes
To Consolidated Financial Statements appearing in Public Service
Company of North Carolina, Incorporated's Annual Report on Form 10-K
for the year ended December 31, 2001, and Note 2 and Note 4 of Notes To
Condensed Consolidated Financial Statements appearing in this Quarterly
Report on Form 10-Q.
Item 2, 3, and 5 are not applicable.
Item 4. Submission of Matters to a Vote of Security-Holders (not applicable
for South Carolina Electric & Gas Company and Public Service Company of North
Carolina, Incorporated)
- -------------------------------------------------------------------
The Annual Meeting of Shareholders of SCANA Common Stock (No Par Value)
was held on May 2, 2002. The following matters were voted upon at the
meeting.
1. To elect four (4) Class III Directors for the terms specified in the
Proxy Statement.
Number of Voting Number of Shares Total
Shares Voting Voting to Shares
Nominee For Withhold Authority Voted
Bill L. Amick 89,418,970 1,355,442 90,774,412
Elaine T. Freeman 89,512,340 1,262,072 90,774,412
D. Maybank Hagood 89,345,310 1,429,102 90,774,412
William B. Timmerman 82,805,416 7,968,996 90,774,412
2. To approve the appointment of Deloitte & Touche as independent
accountants for the Corporation.
Number of Shares
FOR 87,294,054
AGAINST 3,148,042
ABSTAIN 332,316
------ -------
TOTAL 90,774,412
Percent of FOR votes of those shares actually voting for this proposal: 96.2%
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits
SCANA Corporation, South Carolina Electric & Gas Company and
Public Service Company of North Carolina, Incorporated:
Exhibits filed with this Quarterly Report on Form 10-Q are
listed in the following Exhibit Index. Certain of such exhibits
which have heretofore been filed with the Securities and
Exchange Commission and which are designated by reference to
their exhibit numbers in prior filings are hereby incorporated
herein by reference and made a part hereof.
B. Reports on Form 8-K during the second quarter 2002 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)
August 13, 2002 By: s/James E. Swan, IV
---------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
-------------------------------------
(Registrant)
August 13, 2002 By: s/James E. Swan, IV
------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
(Registrant)
August 13, 2002 By: s/James E. Swan, IV
------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
1.01 X Amendment No. 1 to Selling Agency Agreement
dated as of July 30, 2002 between
SCANA Corporation and each of the Agents
named in the Selling Agency Agreement -
UBS Warburg LLC; Credit Suisse First Boston
Corporation, Banc of America
Securities LLC and Wachovia Securities,
Inc. , formerly known as First Union
Securities, Inc. (Filed herewith)
1.02 X Joinder Agreement dated as of August 7,
2002 between SCANA Corporation and BNY
Capital Markets, Inc. (Filed herewith)
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 Amendment of SCE&G dated March
13, 2002 (Filed herewith)
3.09 X Articles of Amendment of SCE&G dated May 9,
2002 (Filed herewith)
3.10 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)
3.11 X Articles of Amendment of PSNC (formerly New
Sub II, Inc.) as adopted on February
10, 2001 (Filed as Exhibit 3.02 to
Registration Statement No. 333-45206)
3.12 X Articles of Correction of PSNC dated
February 11, 2001 (Filed as Exhibit 3.03 to
Registration Statement No. 333-45206)
3.13 X By-Laws of SCANA as revised and amended on
December 13, 2001 (Filed as Exhibit
3.01 to Registration Statement No.
333-68266)
3.14 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)
3.15 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)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
4.01 X Articles of Exchange of South Carolina Electric
and Gas Company and SCANA Corporation (Filed as
Exhibit 4-A to Post-Effective Amendment
No. 1 to Registration Statement No. 2-90438)
4.02 X Indenture dated as of November 1, 1989 between
SCANA Corporation and The Bank of New York, as
Trustee (Filed as Exhibit 4-A to Registration
Statement No. 33-32107)
4.03 X X Indenture dated as of January 1, 1945, between
the South Carolina Power Company and Central
Hanover Bank and Trust Company, as Trustee, as
supplemented by three Supplemental Indentures
dated respectively as of May 1, 1946, May 1, 1947
and July 1, 1949 (Filed as Exhibit 2-B to
Registration Statement No. 2-26459)
4.04 X X Fourth Supplemental Indenture dated as of April
1, 1950, to Indenture referred to in Exhibit
4.03, pursuant to which SCE&G assumed said
Indenture (Filed as Exhibit 2-C to Registration
Statement No. 2-26459)
4.05 X X Fifth through Fifty-third Supplemental Indentures
to Indenture referred to in Exhibit 4.03 dated as
of the dates indicated below and filed as
exhibits to the Registration Statements whose
file numbers are set forth below
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-O to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 2-B to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 2-A-3 to Registration No. 33-38580
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
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
June 1, 1986 Exhibit 4-D to Registration No. 33-49421
September 1, 1987 Exhibit 4-D to Registration No. 33-49421
January 1, 1989 Exhibit 4-D to Registration No. 33-49421
January 1, 1991 Exhibit 4-D to Registration No. 33-49421
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
May 1, 1999 Exhibit 4.04 to Registration No. 333-86387
4.06 X X Indenture dated as of April 1, 1993 from South
Carolina Electric & Gas Company to
NationsBank of Georgia, National Association
(Filed as Exhibit 4-F to Registration
Statement No. 33-49421)
4.07 X X First Supplemental Indenture to Indenture
referred to in Exhibit 4.06 dated as of
June 1, 1993 (Filed as Exhibit 4-G to
Registration Statement No. 33-49421)
4.08 X X Second Supplemental Indenture to Indenture
referred to in Exhibit 4.06 dated as of
June 15, 1993 (Filed as Exhibit 4-G to
Registration Statement No. 33-57955)
4.09 X X Trust Agreement for SCE&G Trust I (Filed as
Exhibit 4.03 to Registration Statement
No. 333-49960)
4.10 X X Certificate of Trust of SCE&G Trust I (Filed as
Exhibit 4.04 to Registration
Statement No. 333-49960)
4.11 X X Junior Subordinated Indenture for SCE&G Trust I
(Filed as Exhibit 4.05 to
Registration Statement No. 333-49960)
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as
Exhibit 4.06 to Registration
Statement No. 333-49960)
4.13 X X Amended and Restated Trust Agreement for SCE&G
Trust I (Filed as Exhibit 4.07 to
Registration Statement No. 333-49960)
4.14 X X Indenture dated as of January 1, 1996 between
PSNC 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)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
4.16 X X Second Supplemental Indenture dated as of
December 15, 1996 between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit
4.10 to Registration Statement No. 333-45206)
4.17 X X Third Supplemental Indenture dated as of
February 10, 2001 between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit
4.11 to Registration Statement No. 333-45206)
4.18 X X Fourth Supplemental Indenture dated as of
February 12, 2001 between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit 4.05 to Registration
Statement No. 333-68516)
4.19 X X PSNC $150 million medium-term note issued
February 16, 2001 (Filed as Exhibit 4.06 to
Registration Statement No. 333-68516)
10.01 X SCANA Executive Deferred Compensation Plan as
amended July 1, 2001 (Filed as Exhibit 10.01 to
Form 10-Q for the quarter ended September 30,
2001)
10.02 X SCANA Supplemental Executive
Retirement Plan as amended July
1, 2001 (Filed as Exhibit 10.02
to Form 10-Q for the quarter
ended September 30, 2001)
10.03 X SCANA Key Executive Severance
Benefits Plan as amended July 1,
2001 (Filed as Exhibit 10.03 to
Form 10-Q for the quarter ended
September 30, 2001)
10.03a X SCANA Supplementary Key
Executive Severance Benefits Plan
as amended July 1, 2001 (Filed as
Exhibit 10.03a to Form 10-Q for
the quarter ended September 30,
2001)
10.04 X SCANA Performance Share Plan as
amended and restated effective
January 1, 1998 (Filed as Exhibit
10 (e) to Registration Statement
No. 333-86803)
10.05 X SCANA Long-Term Equity Compensation Plan dated
January 2001 filed as Exhibit
4.04 to Registration Statement No. 333-37398)
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, 2001(Filed as Exhibit 10.06
to Registration Statement No. 333-45206)
10.15 X Service Agreement between SCE&G and SCANA Services,
Inc., effective April 1, 2001 (Filed as Exhibit
10.15 to Form 10-Q for the quarter ended September
30, 2001)
99.1 X Certification of Principal Executive Officer (Filed
herewith)
99.2 X Certification of Principal Financial Officer (Filed
herewith)
99.3 X Certification of Principal Executive Officer (Filed
herewith)
99.4 X Certification of Principal Financial Officer (Filed
herewith)
99.5 X Certification of Principal Executive Officer (Filed
herewith)
99.6 X Certification of Principal Financial Officer (Filed
herewith)