UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 April 30, 2002
- ---------- ------------ -------------------
SCANA Corporation Without Par Value 104,730,709
South Carolina Electric & Gas Company Par Value $4.50 Per Share 40,296,147(a)
Public Service Company of North
Carolina, Incorporated Without Par Value 1,000(a)
(a)Held beneficially and of record by SCANA Corporation.
This combined Form 10-Q is separately filed by SCANA Corporation, South
Carolina Electric & Gas Company and Public Service Company of North Carolina,
Incorporated. Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no representation as
to information relating to the other companies.
Public Service Company of North Carolina, Incorporated meets the
conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and
therefore is filing this form with the reduced disclosure format allowed under
General Instruction H(2).
INDEX
Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section......................................... 3
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of March 31, 2002
and December 31, 2001 ........................................... 4
Condensed Consolidated Statements of Operations for the
Periods Ended March 31, 2002 and 2001........................... 6
Condensed Consolidated Statements of Cash Flows for the
Periods Ended March 31, 2002 and 2001.......................... 7
Condensed Consolidated Statements of Comprehensive
Income......................................................... 8
Notes to Condensed Consolidated Financial Statements.............. 9
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 18
Item 3. Quantitative and Qualitative Disclosures About Market Risk........ 24
South Carolina Electric & Gas Company Financial Section.................... 26
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of March 31, 2002
and December 31, 2001 ............................................ 27
Condensed Consolidated Statements of Income for the Periods
Ended March 31, 2002 and 2001.................................... 29
Condensed Consolidated Statements of Cash Flows for the
Periods Ended March 31, 2002 and 2001............................ 30
Notes to Condensed Consolidated Financial Statements............... 31
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations......................................... 36
Item 3. Quantitative and Qualitative Disclosures About Market Risk......... 40
Public Service Company of North Carolina, Incorporated Financial Section.... 41
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of March 31, 2002
and December 31, 2001 .......................................... 42
Condensed Consolidated Statements of Income for the
Periods Ended March 31, 2002 and 2001........................... 43
Condensed Consolidated Statements of Cash Flows for
the Periods Ended March 31, 2002 and 2001....................... 44
Notes to Condensed Consolidated Financial Statements............... 45
Item 2. Management's Narrative Analysis of Results of Operations........... 48
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.................................................. 50
Item 6. Exhibits and Reports on Form 8-K................................... 50
Signatures.................................................................. 51
Exhibit Index............................................................... 54
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- -------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2002 2001
- -------------------------------------------------------------------------------
Assets
Utility Plant:
Electric $4,875 $4,855
Gas 1,540 1,536
Other 194 187
- -------------------------------------------------------------------------------
Total 6,609 6,578
Less accumulated depreciation and amortization 2,409 2,364
- -------------------------------------------------------------------------------
Total 4,200 4,214
Construction work in progress 620 544
Nuclear fuel, net of accumulated amortization 51 45
Acquisition adjustments, net of accumulated
amortization 460 460
- -------------------------------------------------------------------------------
Utility Plant, Net 5,331 5,263
- -------------------------------------------------------------------------------
Nonutility Property, Net of Accumulated Depreciation 92 93
Investments 192 191
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Nonutility Property and Investments, Net 284 284
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 656 212
Receivables (net of allowance for uncollectible
accounts of $40 in 2002 and $37 in 2001) 413 424
Inventories (at average cost):
Fuel 125 164
Materials and supplies 60 59
Emission allowances 14 13
Prepayments 21 21
Investments 274 664
- -------------------------------------------------------------------------------
Total Current Assets 1,563 1,557
- -------------------------------------------------------------------------------
Deferred Debits:
Environmental 32 34
Nuclear plant decommissioning fund 81 79
Pension asset, net 246 239
Other regulatory assets 202 210
Other 150 156
- -------------------------------------------------------------------------------
Total Deferred Debits 711 718
- -------------------------------------------------------------------------------
Total $7,889 $7,822
===============================================================================
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ---------------------------------------------------------------- ---------------
March 31, December 31,
Millions of dollars 2002 2001
- ---------------------------------------------------------------- ---------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,205 $2,194
Preferred stock (Not subject to purchase
or sinking funds) 106 106
- ---------------------------------------------------------------- ---------------
Total Stockholders' Investment 2,311 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 2,980 2,646
- ---------------------------------------------------------------- ---------------
Total Capitalization 5,351 5,006
- ---------------------------------------------------------------- ---------------
Current Liabilities:
Short-term borrowings 98 165
Current portion of long-term debt 599 739
Accounts payable 231 275
Customer deposits 41 41
Taxes accrued 90 82
Interest accrued 58 45
Dividends declared 36 34
Deferred income taxes, net 57 154
Other 23 26
- ---------------------------------------------------------------- ---------------
Total Current Liabilities 1,233 1,561
- ---------------------------------------------------------------- ---------------
Deferred Credits:
Deferred income taxes, net 755 720
Deferred investment tax credits 117 118
Reserve for nuclear plant decommissioning 81 79
Postretirement benefits 124 122
Other regulatory liabilities 106 100
Other 122 116
- ---------------------------------------------------------------- ---------------
Total Deferred Credits 1,305 1,255
- ---------------------------------------------------------------- ---------------
Total $7,889 $7,822
================================================================ ===============
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars, except per share amounts 2002 2001
- --------------------------------------------------------------------------------
Operating Revenues:
Electric $302 $340
Gas - regulated 296 467
Gas - nonregulated 224 511
- --------------------------------------------------------------------------------
Total Operating Revenues 822 1,318
- --------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 74 67
Purchased power 5 48
Gas purchased for resale 378 816
Other operation and maintenance 127 128
Depreciation and amortization 54 56
Other taxes 31 30
- --------------------------------------------------------------------------------
Total Operating Expenses 669 1,145
- --------------------------------------------------------------------------------
Operating Income 153 173
- --------------------------------------------------------------------------------
Other Income (Loss):
Other income, including allowance for
equity funds used during construction 19 13
Gain on sale of investments and assets 15 9
Impairment of investments (244) -
- --------------------------------------------------------------------------------
Total Other Income (Loss) (210) 22
- --------------------------------------------------------------------------------
Income (Loss) Before Interest Charges, Income
Taxes and Preferred Stock Dividends (57) 195
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction 51 62
Preferred Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 1
- ------------------------------------------------------------------- ------------
Income (Loss) Before Income Taxes and Preferred
Stock Dividends (109) 132
Income Tax Expense (Benefit) (39) 51
- ---------------------------------------------------------------------- --------
Income (Loss) Before Preferred Stock Dividends (70) 81
Cash Dividends on Preferred Stock of Subsidiary
(At stated rates) 2 2
- ---------------------------------------------------------------------- ---------
Net Income (Loss) $(72) $79
====================================================================== =========
====================================================================== =========
Basic and Diluted Earnings (Loss) Per Share $(.68) $.75
Weighted Average Shares Outstanding (millions) 104.7 104.7
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income (loss) $(72) $79
Adjustments to reconcile net income
(loss) to net cash provided from operating activities:
Depreciation and amortization 55 58
Amortization of nuclear fuel 5 1
Gain on sale of investments and assets (15) (9)
Hedging activities 29 (7)
Impairment on investments 244 -
Allowance for funds used during construction (10) (4)
Over (under) collection, fuel adjustment clauses 4 -
Changes in certain assets and liabilities:
(Increase) decrease in receivables 14 66
(Increase) decrease in inventories 37 (4)
(Increase) decrease in prepayments - (15)
(Increase) decrease in pension asset (7) (10)
(Increase) decrease in other regulatory assets 1 1
Increase (decrease) in deferred income taxes, net (125) 44
Increase (decrease) in regulatory liabilities 10 (1)
Increase (decrease) in postretirement benefits 2 2
Increase (decrease) in accounts payable (37) (112)
Increase (decrease) in taxes accrued 8 (45)
Other, net 39 (30)
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 182 14
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (117) (78)
Proceeds from sale of investments and assets 313 24
Increase in nonutility property (2) (12)
Investments in affiliates (16) (26)
- ---------------------------------------------------------------------- ---------
- ---------------------------------------------------------------------- ---------
Net Cash Provided From (Used For) Investing Activities 178 (92)
- ---------------------------------------------------------------------- ---------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149
Issuance of notes and loans 397 350
Repayments:
First and Refunding Mortgage Bonds (104) -
First Mortgage Bonds - (4)
Notes and loans (402) (1)
Dividends and distributions:
Common stock (32) (29)
Preferred stock (3) (3)
Short-term borrowings, net (67) (254)
- ---------------------------------------------------------------------- ---------
Net Cash Provided From Financing Activities 84 208
- ---------------------------------------------------------------------- ---------
Net Increase In Cash and Temporary Investments 444 130
Cash and Temporary Investments, January 1 212 159
- ---------------------------------------------------------------------- ---------
Cash and Temporary Investments, March 31 $656 $289
===================================================================== =========
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized
interest of $3 for 2002 and $2 for $38 $44
2001)
- Income taxes 7 3
Noncash Investing and Financing Activities:
Unrealized gain on securities available for sale,
net of tax 98 148
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- ----------------------------------------------------------------- -------------
Net Income (Loss) $(72) $79
Other Comprehensive Income, net of tax:
Unrealized gains on securities available for sale 93 148
Unrealized gains (losses) on hedging activities 24 (19)
Cumulative effect of change in accounting
for hedging activities - 23
- ----------------------------------------------------------------- -------------
Total Comprehensive Income (1) $45 $231
=============================================================================
(1) Accumulated other comprehensive income (loss) of the Company totaled $4
million and $(113) million as of March 31, 2002 and December 31, 2001,
respectively.
See Notes to Condensed Consolidated Financial
Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2002
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in SCANA Corporation's (the Company)
Annual Report on Form 10-K for the year ended December 31, 2001. These are
interim financial statements, and due to the seasonality of the Company's
business, the amounts reported in the Condensed Consolidated Statements of
Income are not necessarily indicative of amounts expected for the year. In the
opinion of management, the information furnished herein reflects all
adjustments, all of a normal recurring nature except as described in Note 2,
which are necessary for a fair statement of the results for the interim periods
reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This accounting standard requires cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses in different time periods than do enterprises that are not
rate-regulated. As a result, the Company has recorded as of March 31, 2002
approximately $234 million and $106 million of regulatory assets and
liabilities, respectively, including amounts recorded for deferred income tax
assets, and liabilities of approximately $142 million and $84 million,
respectively. The electric and gas regulatory assets of approximately $44
million and $48 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 future acquisitions to be accounted for utilizing the purchase
method. SCANA 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. In
2001, the amount of such amortization expense recorded was $14 million. This
amortization 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.
As required by the provisions of SFAS 142, the Company is performing
initial valuation analyses to determine whether these carrying amounts are
impaired, and if so, the amount of any write-down which might be recorded as the
cumulative effect of the change in accounting principle. As allowed by the
Statement, the Company will have completed the initial stage of the analyses by
June 30, 2002. If any write-downs are indicated by the analyses, they will be
quantified and recorded by the end of 2002. Because the Company is in the early
stages of these analyses, the effect, if any, of the adoption of the impairment
provisions of the Statement is not known; however, if write-downs are considered
necessary, they could be material to the Company's results of operations for
2002.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will adopt
SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows or financial position has not been
determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," were 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.
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
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" (APB 25), and related interpretations. In addition, the Company has
adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based
Compensation."
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
Electric
On April 30, 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.
On September 14, 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 March 31, 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 March 31, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-March 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 March 31, 2002 ($21.5 million) prior to the end of the
year 2005.
Public Service Company of North Carolina, Incorporated
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 March 31, 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-March 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. On December 30, 1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. On June 29, 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million. The Madison County portion of the project was completed at a cost
of approximately $5.8 million, and customers began receiving service in July
2001.
On December 7, 1999 the NCUC issued an order approving SCANA's
acquisition of PSNC. As specified in the NCUC order, PSNC reduced its rates by
approximately $1 million in each of August 2000 and August 2001, and agreed to a
moratorium on general rate cases until August 2005. General rate relief can be
obtained during this period to recover costs associated with materially adverse
governmental actions and force majeure events.
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 March 31, 2002
approximately $38 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 March 31, 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.
Unrealized
Investee Securities (a) Basis Market (b) Gain (Loss)
Held By (c)
- ----------------------------------------------------------------------------------------------- -------------- ---------------
(Millions of dollars)
DTAG SCH 18.3 million ordinary shares $258.0 (e) $274.3 $16.3
ITC SCH 3.1 million common stock 5.8 (d) n/a
SCH 645,153 series A convertible preferred stock 7.2 (d) n/a
SCH 133,664 series B convertible preferred stock 4.0 (d) n/a
ITC^DeltaCom SCH 5.1 million common stock 4.4 1.6 (2.8)
SCH 1.5 million series A convertible preferred stock 2.6 0.9 (1.7)
SCANA 5,215 series B-1 preferred stock convertible into 914,902
shares of common stock 0.8 0.3 (0.5)
SCANA 6,839 series B-2 preferred stock convertible into 2,671,485
shares of common stock 2.3 0.8 (1.5)
SCANA Warrants to purchase approximately 1.0 million shares of
common stock 0.8 0.3 (0.5)
Knology SCH 7.2 million series A preferred stock, convertible into 7.5 5.0 (d) n/a
million
shares of common stock
SCH Warrants to purchase 159,000 shares of series A convertible
preferred stock, convertible into 164,900 shares of common (d) n/a
stock
SCH 8.3 million series C preferred stock, convertible into 8.3 25.0 (d) n/a
million
shares of common stock
Knology
Broadband SCH $102,571,000 face amount, 11.875% Senior Discount notes due 79.1 (d) n/a
2007
(a) Convertible preferred stock is convertible into common stock at any time.
(b) As converted, based on market value of underlying common stock, where
applicable.
(c) Amounts are included in accumulated other comprehensive income (loss), net
of taxes.
(d) Market value not readily determinable.
(e) Reflects write-down for "other than temporary" impairment as discussed
below.
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.
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 of
approximately $23.0 million, net of tax, as the effect of a change in accounting
principle (transition adjustment) to other comprehensive income on January 1,
2001. This amount represents the reclassification of unrealized gains that were
deferred and reported as liabilities at December 31, 2000. Substantially all of
this amount was reclassified into earnings in 2001 as a component of gas cost.
The Company recognized losses of approximately $(19.0) million, net of
tax and gains of $4.9 million, net of tax as a result of qualifying cash flow
hedges whose hedged transactions occurred during the three months ended March
31, 2002 and 2001, respectively. These gains and losses were recorded in cost of
gas. Losses due to hedge ineffectiveness were insignificant. The Company
estimates that substantially all of the March 31, 2002 balance of $(2) million,
net of tax, will be reclassified from accumulated other comprehensive income to
earnings in 2002 as an increase in gas cost if market prices remain stable. As
of March 31, 2002 substantially all of the Company's cash flow hedges settle by
their terms before the end of 2003.
Certain derivatives that SCPC utilizes to hedge its gas purchasing
activities are recoverable through its fuel adjustment clauses. 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 March 31, 2002 the estimated fair value of this swap was $1.2 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.
On December 19, 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 March 31, 2002 the
fair value of these swaps was not significant.
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 March 31, 2002 include
the following:
A. Lake Murray Dam Reinforcement
On October 15, 1999 the FERC notified SCE&G of its agreement with
SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case
of an extreme earthquake. Construction for the project and related activities,
which began in the third quarter of 2001 is expected to cost approximately $250
million and be completed in 2005. Any costs incurred by SCE&G are expected to be
recoverable through electric rates.
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 June 2002. SCE&G anticipates that major remediation activities will
be completed in 2003, with certain monitoring activities continuing until 2007.
As of March 31, 2002, SCE&G has spent approximately $17.0 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 between 2003-2005. SCE&G has spent approximately
$2.0 million related to these sites and expects to incur 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 that the cost to
remediate the sites would range 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 PRPs. At March 31,
2002 PSNC has recorded a liability and associated regulatory asset of $9.0
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 incurred will be recoverable through gas rates.
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.
Disclosure of Reportable Segments
(Millions of dollars)
- ----------------------------------------------------------------------------------------------
Three Months Ended External Intersegment Operating Net Segment
March 31, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- ----------------------------------------------------------------------------------------------
Electric Operations $302 $149 $87 n/a $5,124
Gas Distribution 240 1 54 n/a 1,639
Gas Transmission 56 73 (8) n/a 293
Retail Gas Marketing 185 - n/a $14 100
Energy Marketing 39 - n/a (1) 73
Telecommunications Investments - - - (150) 470
All Other - 1 21 15 606
Adjustments/Eliminations - (224) (1) 50 (416)
- ----------------------------------------------------------------------------------------------
Consolidated Total $822 - $153 $(72) $7,889
==============================================================================================
- ---------------------------------------------------------------------------------------------
Three Months Ended External Intersegment Operating Net Segment
March 31, 2001 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------------------------------------------------------------------
Electric Operations $340 $74 $94 n/a $5,002
Gas Distribution 385 - 60 n/a 1,654
Gas Transmission 82 119 - n/a 292
Retail Gas Marketing 263 - n/a $9 160
Energy Marketing 248 - n/a 3 138
Telecommunications Investments - - - (2) 629
All Other 18 5 21 26 283
Adjustments/Eliminations (18) (198) (2) 43 (357)
- --------------------------------------------------------------------------------------------
Consolidated Total $1,318 - $173 $79 $7,801
================================== =========== ============ ============ ========== ========
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 annual 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 2005. This requirement would gradually escalate to
ten percent in 2019. Substantial penalties would be levied from failure to
comply. Electric cooperatives and municipal utilities would be exempt from these
requirements. The Company is not able to predict whether this or similar
legislation 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 SCE&G's proposed natural gas-fired generating
station in Jasper County, South Carolina. In December 2001 SCG filed an
application with FERC for a Certificate of Public Convenience and Necessity to
acquire and build a pipeline from Elba Island, Georgia to Jasper County, South
Carolina. 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 through a bidding process to serve low-income and
high credit risk customers, o allows Georgia's 42 non-profit Electric Membership
Corporations 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 to implement and monitor 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.
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 and the incurrence of additional
short-term and long-term indebtedness. Sales of additional equity securities may
also occur. The Company expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the foreseeable future.
The Company's ratio of earnings to fixed charges for the 12 months ended March
31, 2002 was 3.47.
The following table summarizes how the Company generated and used funds
for property additions and construction expenditures during the three months
ended March 31, 2002 and 2001:
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Net cash provided from operating activities $182 $14
Net cash provided from financing activities 84 208
Cash provided from sale of investments and assets 313 24
Cash and temporary investments available
at the beginning of the period 212 159
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Net cash available for property additions
and construction expenditures $791 $405
================================================================================
Funds used for utility property additions
and construction expenditures,
net of noncash allowance for funds
used during construction $117 $78
Funds used for nonutility property additions $2 $12
================================================================================
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.
SCE&G is constructing a $256 million gas turbine generator project in
Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas
to produce 300 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. The turbine project is scheduled to be completed by
June 2002.
In October 1999 FERC notified SCE&G of its agreement with SCE&G's plan
to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001, is expected to cost approximately $250 million and be
completed in 2005. Any costs incurred by SCE&G are expected to be recoverable
through electric rates.
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
will be supplied with natural gas by SCG Pipeline, Inc. 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.
Environmental Matters
For information on environmental matters see Note 6C of Notes to
Condensed Consolidated Financial Statements.
Other Matters
Radio Service Network
In April 2002 SCI sold its 800 Mhz radio service network within South
Carolina to Motorola, Inc. for an after tax gain of approximately $9 million.
Telecommunications Investments
For information on telecommunications investments, see Note 5,
"Financial Instruments," of Notes to Condensed Consolidated Financial
Statements.
Transit
SCE&G and the City of Columbia (City) have entered into an agreement
whereby a regional transit authority will 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 is subject to various approvals by Federal and state regulatory
agencies.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2002
AS COMPARED TO THE CORRESPONDING PERIOD IN 2001
Earnings (Loss) and Dividends
Earnings (loss) per share of common stock for the three months ended
March 31, 2002 and 2001 were as follows:
- -------------------------------------------------------------------------------
Three Months Ended
2002 2001
- ----------------------------------------------------------------- -------------
Earnings (loss) derived from:
Operations $.74 $.71
Non-recurring items:
Realized gain from stock investment .10 -
Sale of subsidiary assets - .04
Investment impairment (1.52) -
-------------
- ----------------------------------------------------------------- -------------
Earnings (loss) per weighted average share $(.68) $.75
================================================================= =============
Earnings per share from operations for the three months ended March 31,
2002 increased $.03 as compared to 2001. The Company experienced a decrease in
interest expense of $.06, an increase in its allowance for funds used during
construction (AFC) of $.04, improvements in the operating results of its
appliance protection and plant management businesses of $.02, decreases in
operation and maintenance expense of $.01 and depreciation expense of $.01 and
other operational improvements of $.02. These improvements were partially offset
by a decline in gas margin of $.12 and in electric margin of $.01.
For the last several years, the market value of the Company's retirement
plan assets has exceeded the total actuarial present value of accumulated plan
benefits. Pension income for the three months ended March 31, 2002 was $6.6
million, compared to $9.6 million for the corresponding period in 2001. As a
result of pension income, employee benefit expenses were reduced approximately
$3.6 million for the three months ended March 31, 2002, compared to $5.2 million
for the corresponding period in 2001. In addition, other income increased $2.0
million for the three months ended March 31, 2002, compared to $3.0 million for
the corresponding period in 2001.
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). The Company recognized a gain of $.04 per share in
connection with the sale of the assets of SCANA Security in March 2001.
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 nine percent and approximately three percent of income (loss)
before taxes for the three months ended March 31, 2002 and 2001, respectively.
The increase in AFC for the three months ended March 31, 2002, compared to the
corresponding period in 2001, is primarily the result of increased construction
expenditures related to the Urquhart gas turbine generator project and the Lake
Murray Dam project (see discussion at LIQUIDITY AND CAPITAL RESOURCES).
The Company's Board of Directors declared the following quarterly
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
- -------------------- -------------------- --------------------- ----------------
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 for the three months
ended March 31, 2002, when compared to the corresponding period in 2001, were as
follows:
-------------------------------------------------------------------------------
Three Months Ended
Millions of dollars 2002 2001 Change
-------------------------------------------------------------------------------
Electric operating revenue $302.6 $340.2 $(37.6) (11.1)%
Less: Fuel used in generation 74.3 67.3 7.0 10.4%
Purchased power 5.0 48.5 (43.5) (89.7)%
----------------------------------------------------------------
Margin $223.3 $224.4 $(1.1) (0.5)%
===============================================================================
Changes in electric operations sales margins for the three months ended
March 31, 2002 reflect milder weather, which was partially offset by customer
growth. Higher purchased power costs during 2001 related primarily to plant
outages for maintenance and repairs.
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, for the three months ended March 31, 2002, when
compared to the corresponding period in 2001, were as follows:
- --------------------------------------- ----------------------------------------
Three Months Ended
Millions of dollars 2002 2001 Change
- --------------------------------------------- ---------- -----------------------
Gas distribution operating revenue $241.0 $385.5 $(144.5) (37.5)%
Less: Gas purchased for resale 140.1 $279.5 (139.4) (49.9)%
- --------------------------------------------- ---------- -----------
Margin $100.9 $106.0 $(5.1) (4.8)%
============================================= ========== =======================
Changes in gas distribution sales margin for the three months ended
March 31, 2002 reflect milder weather and weak economic conditions. Revenues and
purchases were impacted by extremely high commodity natural gas prices in early
2001.
Gas Transmission
Gas Transmission is comprised of the operations of South Carolina
Pipeline Corporation. Changes in the gas transmission sales margins, including
transactions with affiliates, for the three months ended March 31, 2002, when
compared to the corresponding period in 2001, were as follows:
- --------------------------------------- ------- ------------ ------------ -----
Three Months Ended
Millions of dollars 2002 2001 Change
- ------------------------------------------- ----------- -----------------------
Gas transmission operating revenue $128.1 $201.3 $(73.2) (36.4)%
Less: Gas purchased for resale 128.5 192.1 (63.6) (33.1)%
- ------------------------------------------- ----------- -----------
Margin $(0.4) $9.2 $(9.6) *
=========================================== =========== =======================
*Greater than 100%
Gas transmission sales margins for the three months ended March 31, 2002
decreased primarily as a result of reduced industrial margins due to the
unfavorable competitive position of natural gas relative to alternate fuels.
Revenues and purchases were impacted by extremely high commodity natural gas
prices in early 2001.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in Georgia's deregulated natural gas
market. Retail gas marketing revenues and net income for the three months ended
March 31, 2002, when compared to the corresponding period in 2001, were as
follows:
- ---------------------------------- ----------- --------- --------- -----------
Three Months Ended
Millions of dollars 2002 2001 Change
- ---------------------------------- ---------- ---------- ---------------------
Operating revenues $185.0 $263.0 $(78.0) (29.7)%
Net income (loss) 13.9 9.3 4.6 49.5%
================================== ========== =========== ========= ==========
Operating revenues for the three months ended March 31, 2002 decreased
primarily as a result of the decline in commodity natural gas prices from the
record levels experienced in 2001. Net income for the three months improved
primarily due to lower bad debt expense and other operating expenses.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Changes in energy marketing operating
revenues, including transactions with affiliates, and net income (loss) for the
three months ended March 31, 2002, when compared to the corresponding period in
2001, were as follows:
- --------------------------------- ------------ --------- --------- -------------
Three Months Ended
Millions of dollars 2002 2001 Change
- --------------------------------- ----------- ----------- ----------------------
Operating revenues $39.0 $247.7 $(208.7) (84.3)%
Net income (loss) (1.1) 3.5 (4.6) *
================================= =========== =========== ============ =========
*Greater than 100%
Operating revenues for the three months ended March 31, 2002 decreased
primarily as a result of the decline in commodity natural gas prices from the
record levels experienced in 2001and due to less favorable weather than in early
2001. Net income (loss) for the three months ended March 31, 2002 decreased
primarily as a result of the winding down of operations for SCANA Energy
Trading, LLC during the first quarter of 2002 and the closing of the Midwest
office.
Other Operating Expenses
Changes in other operating expenses for the three months ended March 31,
2002, when compared to the corresponding period in 2001, were as follows:
- --------------------------------------- --------- ---------- --------- --------
Three Months Ended
Millions of dollars 2002 2001 Change
- --------------------------------------- ---------- --------- ------------------
Other operation and maintenance $126.4 $128.3 $(1.9) (1.5)%
Depreciation and amortization 53.8 55.6 (1.8) (3.2)%
Other taxes 31.2 29.9 1.3 4.3%
- --------------------------------------- --------- ---------- ---------
Total $211.4 $213.8 $(2.4) (1.1)%
======================================= ========= ========== ========= =========
Other operation and maintenance expense for the three months decreased
primarily as a result of lower bad debt expense and other costs. Depreciation
and amortization for the three 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 due to increased property taxes.
Other Income
Other income for the three months ended March 31, 2002 decreased when
compared to the corresponding period in 2001, primarily due to the investment
impairment recorded in March 2002 in connection with the Company's investment in
DTAG, which was partially offset by the non-recurring gain recognized in March
2002 in connection with the Company's sale of stock of DTAG, and the March 2001
gain on the sale of the assets of SCANA Security (see Note 5 of Notes to
Condensed Consolidated Financial Statements).
Interest Expense
Interest expense for the three months ended March 31, 2002 decreased
when compared to the corresponding period in 2001 primarily due to declining
variable interest rates, which was partially offset by increased debt.
Income Taxes
Income taxes for the three months ended March 31, 2002 decreased
approximately $91.0 million when compared to the corresponding period in 2001.
This change is primarily due to a reduction of deferred income taxes in
connection with the non-recurring investment impairment recorded in March 2002
arising from the Company's investment in DTAG (see Note 5 of Notes to Condensed
Consolidated Financial Statements).
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held
for purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
As of March 31, 2002 Expected Maturity Date
- -------------------- ----------------------
Millions of dollars
There- Fair
Liabilities 2002 2003 2004 2005 2006 after Total Value
- ---------------------------------------- --------- ---------- ---------- ---------- ---------- ------------ ---------
- ---------------------------------------- --------- ---------- ---------- ---------- ---------- ------------ ---------
Long-Term Debt:
Fixed Rate ($) 36.5 298.6 187.1 182.0 162.8 2,174.6 3,041.6 3,027.4
Average Fixed Interest Rate 7.24 6.38 7.58 7.43 8.63 6.79
6.94
Variable Rate ($) 300.0 202.0 150.0 - - 652.0 648.7
-
Average Variable Interest Rate 2.48 2.90 2.50 - - 2.61
-
Interest Rate Swap:
Pay Variable/Receive Fixed ($) - - 12.9 - - 332.0 344.9
0.9
Average Pay Interest Rate - - - - 2.60 2.79
7.83
Average Receive Interest Rate - - 10.00 - - 6.21 6.35
While a decrease in interest rates would increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.
In addition, 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 $79.1 million . As these notes are not publicly traded,
determination of their fair value is not practicable.
Commodity price risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.
As of March 31, 2002
Millions of dollars, except settlement price and strike price
Natural Gas Derivatives: Expected Maturity in 2002 Expected Maturity in 2003
- ------------------------- ------------------------------------------------------
Settlement Contract Fair Settlement Contract Fair
Price (a) Amount Value Price (a) Amount Value
Futures Contracts:
Long($) 3.47 71.5 72.7 3.89 23.9 29.5
Short($) 3.33 0.9 0.7 - - -
Strike Contract Strike Contract
Price Amount Price Amount
(a) (a)
Options:
Purchased put (long)($) $3.47 $31.9 - -
Sold put (short)($) $3.55 $50.1 $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 fuel adjustment
clauses.
Equity price risk - Investments in telecommunications companies' equity
securities are carried at their market value or, if market value is not readily
determinable, at their cost. The Company's investments in such securities
totaled $325.4 million at March 31, 2002. A temporary decline in value of ten
percent would result in a $32.5 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 $32.5 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)
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Assets
Utility Plant:
Electric $4,582 $4,563
Gas 428 425
Other 194 188
- --------------------------------------------------------------------------------
Total 5,204 5,176
Less accumulated depreciation and amortization 1,875 1,841
- --------------------------------------------------------------------------------
Total 3,329 3,335
Construction work in progress 578 511
Nuclear fuel, net of accumulated amortization 51 45
- --------------------------------------------------------------------------------
Utility Plant, Net 3,958 3,891
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 24 24
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 81 78
Receivables 222 212
Receivables - affiliated companies 1 4
Inventories (at average cost):
Fuel 44 39
Materials and supplies 50 48
Emission allowances 14 13
Prepayments 11 6
- --------------------------------------------------------------------------------
Total Current Assets 423 400
- --------------------------------------------------------------------------------
Deferred Debits:
Environmental 21 24
Nuclear plant decommissioning fund 81 79
Pension asset, net 246 239
Due from affiliates - postretirement benefits 15 15
Other regulatory assets 185 193
Other 106 97
- --------------------------------------------------------------------------------
Total Deferred Debits 654 647
- --------------------------------------------------------------------------------
Total $5,059 $4,962
================================================================================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $1,766 $1,750
Preferred stock (Not subject to purchase
or sinking funds) 106 106
- --------------------------------------------------------------------------------
Total Stockholders' Investment 1,872 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 3,541 3,328
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 98 165
Current portion of long-term debt 26 28
Accounts payable 99 99
Accounts payable - affiliated companies 58 78
Customer deposits 20 19
Taxes accrued 20 80
Interest accrued 32 27
Dividends declared 36 42
Deferred income taxes, net 11 12
Other 6 8
- --------------------------------------------------------------------------------
Total Current Liabilities 406 558
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes, net 623 599
Deferred investment tax credits 108 109
Reserve for nuclear plant decommissioning 81 79
Due to affiliates - pension asset 16 16
Postretirement benefits 124 122
Regulatory liabilities 90 81
Other 70 70
- --------------------------------------------------------------------------------
Total Deferred Credits 1,112 1,076
- --------------------------------------------------------------------------------
Total $5,059 $4,962
================================================================================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- -------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- -------------------------------------------------------------------------------
Operating Revenues:
Electric $304 $342
Gas 107 157
- -------------------------------------------------------------------------------
Total Operating Revenues 411 499
- -------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 55 50
Purchased power (including affiliated purchases) 33 75
Gas purchased for resale 73 119
Other operation and maintenance 83 79
Depreciation and amortization 42 40
Other taxes 26 26
- -------------------------------------------------------------------------------
Total Operating Expenses 312 389
- -------------------------------------------------------------------------------
Operating Income 99 110
Other Income, Including Allowance for Equity Funds
Used During Construction 9 5
- -------------------------------------------------------------------------------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 108 115
Interest Charges, Net of Allowance for Borrowed
Funds Used During Construction 28 28
Preferred Dividend Requirement of the Company - Obligated
Mandatorily Redeemable Preferred Securities 1 1
- -------------------------------------------------------------------------------
Income Before Income Taxes and Preferred Stock Dividends 79 86
Income Taxes 27 32
- -------------------------------------------------------------------------------
Net Income 52 54
Preferred Stock Cash Dividends Declared (At stated rates) 2 2
- -------------------------------------------------------------------------------
Earnings Available for Common Stockholder $50 $52
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
30
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $52 $54
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 40 41
Amortization of nuclear fuel 5 1
Allowance for funds used during construction (10) (4)
Over (under) collections, fuel adjustment clauses 7 (13)
Changes in certain assets and liabilities:
(Increase) decrease in receivables (7) 42
(Increase) decrease in inventories (8) (9)
(Increase) decrease pension asset (7) (10)
(Increase) decrease other regulatory assets 1 -
Increase (decrease) deferred income taxes, net 23 25
Increase (decrease) other regulatory liabilities 10 5
Increase (decrease) postretirement benefits 2 2
Increase (decrease) in accounts payable (20) (46)
Increase (decrease) in taxes accrued (60) (51)
Other, net (2) (2)
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 26 35
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (103) (64)
Proceeds from sale of assets 1 -
Investments (1) -
- ------------------------------------------------------------------------ -------
Net Cash Used For Investing Activities (103) (64)
- ------------------------------------------------------------------------ -------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149
Repayments:
First and Refunding Mortgage Bonds (104) -
Other long-term debt (1) (1)
Dividends and distributions:
Common stock (40) (42)
Preferred stock (3) (3)
Short-term borrowings, net (67) (95)
- ------------------------------------------------------------------------ -------
Net Cash Provided From Financing Activities 80 8
- ------------------------------------------------------------------------ -------
Net Increase (Decrease) In Cash and Temporary Investments 3 (21)
Cash and Temporary Investments, January 1 78 60
- ------------------------------------------------------------------------ -------
Cash and Temporary Investments, March 31 $81 $39
======================================================================== =======
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of
$4 for 2002 and $2 for 2001) $54 $19
- Income taxes $3 2
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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 except as described in Note 2,
which are necessary for a fair statement of the results for the interim periods
reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This accounting standard requires cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses in different time periods than do enterprises that are not
rate-regulated. As a result, the Company has recorded as of March 31, 2002
approximately $206 million and $90 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets, and
liabilities of approximately $125 million and $79 million, respectively. The
electric and gas regulatory assets of approximately $44 million and $37 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 a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will adopt
SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows or financial position has not been
determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" were 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.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2002.
2. RATE AND OTHER REGULATORY MATTERS
Electric
On April 30, 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 20012
On September 14, 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 March 31,
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, 2001through March 31, 2002 was as follows:
Rate Per Therm Effective Date
$.993 January-February 2001
$.793 March-October 2001
$.596 November 2001-March 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
1.1cents per therm to 3.0 cents per therm, which is intended to provide for the
recovery of the balance remaining at March 31, 2002 ($21.5 million) prior to the
end of the year 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
March 31, 2002 approximately $38 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 March 31, 2002 include
the following:
A. Lake Murray Dam Reinforcement
On October 15, 1999 the Federal Energy Regulatory Commission (FERC)
notified the Company of its agreement with the Company's plan to reinforce Lake
Murray Dam in order to maintain the lake in case of an extreme earthquake.
Construction for the project and related activities, which began in the third
quarter of 2001, is expected to cost approximately $250 million and be completed
in 2005. Any costs incurred by the Company are expected to be recoverable
through electric rates.
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
$25.9 million at March 31, 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 June 2002. The Company
anticipates that major remediation activities will be completed in 2003, with
certain monitoring activities continuing until 2007. As of March 31, 2002, the
Company has spent approximately $170 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 between 2003-2005. The
Company has spent approximately $2.0 million related to these sites and expects
to incur 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 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 local distribution
operations of the Company, 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 Electric Gas All Adjustments/ Consolidated
March 31, 2002 Operations Distribution Other Eliminations Total
- -------------------------------- ------------ ----------------------------------
External Revenue $304 $107 - - $411
Intersegment Revenue 52 - - $(52) -
Operating Income (Loss) 84 16 - (1) 99
Segment Assets 5,124 431 $4 (500) 5,059
- ------------------------------------------ ------------ ------------------------
Three months ended Electric Gas All Adjustments/ Consolidated
March 31, 2001 Operations Distribution Other Eliminations Total
- --------------------------------- ------------ ---------------------------------
External Revenue $342 $157 - - $499
Intersegment Revenue 47 - - $(47) -
Operating Income (Loss) 89 22 - (1) 110
Segment Assets 4,707 419 5 (441) 4,690
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
annual 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
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 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.
SCE&G is not able to predict whether this or similar legislation or regulatory
action 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.
The following table summarizes how SCE&G generated and used funds for
property additions and construction expenditures during the three months ended
March 31, 2002 and 2001:
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- -------------------------------------------------------------------- -----------
Net cash provided from operating activities $26 $35
Net cash provided from for financing activities 80 8
Cash and temporary cash investments available at
the beginning of the period 78 60
- -------------------------------------------------------------------- -----------
Net cash available for utility property additions
and construction expenditures $184 $103
==================================================================== ===========
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $103 $64
==================================================================== ===========
SCE&G anticipates that the remainder of its 2002 cash requirements will
be met through internally generated funds and the incurrence of additional
short-term and long-term indebtedness. SCE&G expects that it has or can obtain
adequate sources of financing to meet its projected cash requirements for the
next 12 months and for the foreseeable future. SCE&G's ratio of earnings to
fixed charges for the 12 months ended March 31, 2002 was 3.69.
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 is constructing a $256 million gas turbine generator project in
Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas
to produce 300 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. The turbine project is scheduled to be completed by
June 2002.
In October 1999 FERC notified SCE&G of its agreement with SCE&G's plan
to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001, is expected to cost approximately $250 million and be
completed in 2005. Any costs incurred by SCE&G are expected to be recoverable
through electric rates.
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
will be supplied with natural gas by SCG Pipeline, Inc., an affiliate. 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.
Environmental Matters
For information on environmental matters see Note 5C of Notes To
Condensed Consolidated Financial Statements.
Transit
SCE&G and the City of Columbia (City) have entered into an agreement
whereby a regional transit authority will 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 is subject to various approvals by Federal and State regulatory
agencies.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2002
AS COMPARED TO THE CORRESPONDING PERIOD IN 2001
Earnings and Dividends
Net income components for the three months ended March 31, 2002 and
2001 were as follows:
-----------------------------------------------------------------------------
Three Months Ended
Millions of dollars 2002 2001 Change
----------------------------------------------------------- ----------------
Net income derived from operations $52.0 $53.5 $(1.5) (2.8)%
----------------------------------------------------------- ------- ---------
Net income from operations for the three months ended March 31, 2002
decreased primarily due to milder weather, an increase in other operation and
maintenance expense and a weak economy, which were partially offset by customer
growth.
For the last several years, the market value of the Company's retirement
plan assets has exceeded the total actuarial present value of accumulated plan
benefits. Pension income for the three months ended March 31, 2002 was $6.4
million, compared to $9.2 million for the corresponding period in 2001. As a
result of pension income, employee benefit expenses were reduced approximately
$3.4 million for the three months ended March 31, 2002. For the corresponding
period in 2001, employee benefit expenses were reduced approximately $4.8
million. Additionally, other income increased $2.0 million for the three months
ended March 31, 2002. For the corresponding period in 2001, other income
increased $3.0 million.
Allowance for funds used during construction (AFC) is a utility
accounting practice whereby a portion of the cost of both equity and borrowed
funds used to finance construction (which is shown on the balance sheet as
construction work in progress) is capitalized. Both the equity and the debt
portions of AFC are noncash items of nonoperating income which have the effect
of increasing reported net income. AFC represented approximately eleven percent
and four percent of income before income taxes for the three months ended March
31, 2002 and 2001, respectively. The increase in AFC for the three months ended
March 31, 2002 compared to the corresponding period in 2001, is primarily the
result of increased construction expenditures related to the gas turbine
generator project and the Lake Murray Dam project (see discussion at LIQUIDITY
AND CAPITAL RESOURCES).
SCE&G's Board of Directors declared the following quarterly 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
- --------------------- ------------------- ---------------------- ---------------
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
for the three months ended March 31, 2002, when compared to the corresponding
period in 2001, were as follows:
- ----------------------------------------------------------------------------
Three Months Ended
Millions of dollars 2002 2001 Change
- -------------------------------------- ------------ ------------------------
Electric operating revenue $304.3 $341.5 $(37.2) (10.9)%
Less: Fuel used in generation 55.4 50.0 10.8%
5.4
Purchased power 32.9 74.6 (41.7) (55.9)%
- ------------------------------- -----------
-------- -----------
Margin $216.0 $216.9 $(0.9) (0.4)%
======================================= =========== =========== ============
Changes in electric operations sales margins for the three months ended
March 31, 2002 reflect milder weather, which was partially offset by customer
growth. Higher purchased power costs during 2001 related primarily to plant
outages for repairs and maintenance. Operating revenue decreased due to the
effects of milder weather.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Changes in the gas distribution sales margins for the three months ended
March 31, 2002, when compared to the corresponding period in 2001, were as
follows:
- ----------------------------------------------------------------------------
Three Months Ended
Millions of dollars 2002 2001 Change
- -------------------------------------------- --------- ---------------------
Gas operating revenue $107.1 $157.1 $(50.0) (31.8)%
Less: Gas purchased for resale 72.7 118.9 (46.2) (38.9)%
- ---------------------------------- ----------
---------- ---------
Margin $34.4 $38.2 $(3.8) (9.9)%
============================================ ========= ========== ==========
Gas distribution sales margins for the three months ended March 31, 2002
reflect milder weather and a weak economy. Revenues and purchases for the three
months ended March 31, 2002 were impacted by extremely high commodity natural
gas prices in early 2001. The increased cost of gas was passed on to customers
as discussed in Note 2 in Notes To Condensed Consolidated Financial Statements.
Other Operating Expenses
Changes in other operating expenses for the three months ended March 31,
2002 when compared to the corresponding period in 2001, were as follows:
- -------------------------------------------------------------------------------
Three Months Ended
Millions of dollars 2002 2001 Change
- ------------------------------------------- ----------- -----------------------
Other operation and maintenance $82.8 $78.9 $3.9 4.9%
Depreciation and amortization 41.5 40.5 1.0 2.5%
Other taxes 26.5 25.6 0.9 3.5%
- ------------------------------------ -----------
------- -----------
Total $150.8 $145.0 $5.8 4.0%
=========================================== =========== =========== ===========
Other operating expenses for the three months ended March 31, 2002
increased primarily as a result of higher property insurance costs and reduced
pension income in 2002. The increase in depreciation and amortization expenses
for the three months ended March 31, 2002 resulted primarily from normal
property additions. Other taxes increased primarily as a result of increased
property taxes.
Other Income
Other income for the three months ended March 31, 2002 increased when
compared to the corresponding period in 2001, primarily as a result of the
increase in the equity component of AFC (see AFC discussion at Earnings and
Dividends).
Income Taxes
Income taxes for the three months ended March 31, 2002 decreased when
compared to the corresponding period in 2001, primarily as a result of the
change in operating income.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates.
As of March 31, 2002
Millions of dollars Expected Maturity Date
There- Fair
Liabilities 2002 2003 2004 2005 2006 after Total Value
- -------------------------------------- -----------------------------------------
- -------------------------------------- -----------------------------------------
Long-Term Debt:
Fixed Rate ($) 26.1 129.7 123.9 173.9 154.6 1,147.8 1,756.0 1,717.7
Average Interest Rate 6.74 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)
- --------------------------------------------------------------------------------
March 31, December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Assets
Gas Utility Plant 863 $855
Less accumulated depreciation 296 288
Acquisition adjustment, net of accumulated amortization 439 439
- --------------------------------------------------------------------------------
Gas Utility Plant, Net 1,006 1,006
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 29 29
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 55 18
Restricted cash and temporary investments 2 2
Receivables (net of allowance for
uncollectible accounts of $2
for 2002 and $1 for 2001) 55 70
Receivables - affiliated companies 10 12
Inventories (at average cost):
Stored gas 27 47
Materials and supplies 8 8
- --------------------------------------------------------------------------------
Total Current Assets 157 157
- --------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Due from affiliate-pension asset 11 11
Regulatory assets 11 11
Other 9 7
- --------------------------------------------------------------------------------
Total Deferred Charges and Other Assets 31 29
- --------------------------------------------------------------------------------
Total $1,223 $1,221
================================================================================
================================================================================
Capitalization and Liabilities
Capitalization:
Common equity $731 $715
Long-term debt, net 290 290
- --------------------------------------------------------------------------------
Total Capitalization 1,021 1,005
- --------------------------------------------------------------------------------
Current Liabilities:
Current portion of long-term debt 4 4
Accounts payable 20 41
Accounts payable -affiliated companies 7 10
Taxes accrued 14 5
Customer prepayments and deposits 15 17
Dividends declared and interest accrued 9 6
Other 3 3
- --------------------------------------------------------------------------------
Total Current Liabilities 72 86
- --------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Deferred income taxes, net 86 86
Deferred investment tax credits 2 2
Due to affiliate-postretirement benefits 12 11
Regulatory liabilities 11 14
Other 19 17
- --------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 130 130
- --------------------------------------------------------------------------------
Total $1,223 $1,221
================================================================================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
-------------------------------------------------- ---------------
Operating Revenues $134 $228
Cost of Gas 67 160
-------------------------------------------------- ---------------
Gross Margin 67 68
-------------------------------------------------- ---------------
Operating Expenses:
Operation and maintenance 18 17
Depreciation and amortization 9 10
Other taxes 2 2
-------------------------------------------------- ---------------
Total Operating Expenses 29 29
-------------------------------------------------- ---------------
Operating Income 38 39
Other Income, net 2 1
Interest Charges 6 5
-------------------------------------------------- ---------------
Income Before Income Taxes 34 35
Income Taxes 13 15
-------------------------------------------------- ---------------
Net Income $21 $20
================================================== ===============
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------
Three Months Ended
March 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
Cash Flows From Operating Activities:
Net income $21 $20
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 10 12
Excess distributions (undistributed earnings) of investee - (1)
Over (under) collection, fuel adjustment clause (3) 13
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 16 12
(Increase) decrease in inventories 20 10
(Increase) decrease in regulatory assets - (75)
Increase (decrease) in accounts payable and advances (24) (5)
Increase (decrease) in deferred income taxes, net - 1
Increase (decrease) in accrued taxes 9 18
Other, net (3) 2
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 46 7
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Construction expenditures (9) (11)
Investments - 5
Nonutility and other - 2
- --------------------------------------------------------------------------------
Net Cash Used For Investing Activities (9) (4)
- --------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Issuance of medium-term notes - 149
Repayment of short-term borrowings, net - (125)
Cash dividends - (4)
- --------------------------------------------------------------------------------
Net Cash Provided From Financing Activities - 20
- --------------------------------------------------------------------------------
Net Increase In Cash and Temporary Investments 37 23
Cash and Temporary Investments, January 1 18 8
- --------------------------------------------------------------------------------
Cash and Temporary Investments, March 31 $55 $31
================================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of
$0.2 for 2002 and $0.3 for 2001) $6 $2
- Income taxes 4 -
See Notes to Condensed Consolidated Financial Statements.
47
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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 except as
described in Note 2 which are necessary for a fair statement of the results for
the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This accounting standard requires cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses in different time periods than do enterprises that are not
rate-regulated. As a result, the Company has recorded as of March 31, 2002
approximately $11 million and $11 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax liabilities of
approximately $0.4 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 future 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. For the year ended December 31, 2001, the amount of such amortization
expense recorded was $13 million. The Company has no other intangible assets
subject to amortization as provided in SFAS 142.
As required by the provisions of SFAS 142, the Company is performing an
initial valuation analysis to determine whether this carrying amount is impaired
and, if so, the amount of any write-down which might be recorded as the
cumulative effect of the change in accounting principle. As allowed by the
Statement, the Company will have completed the initial stage of the analysis by
June 30, 2002. If a write-down is indicated by the analysis, it will be
quantified and recorded by the end of 2002. Because the Company is in the early
stages of the analysis, the effect, if any, of the adoption of the impairment
provisions of the Statement is not known; however, if a write-down is considered
necessary, it could be material to the Company's results of operations for 2002.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset. The Company will adopt SFAS 143 effective January
1, 2003. The impact SFAS 143 may have on the Company's results of operations,
cash flows or financial position has not been determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," were 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.
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 March 31, 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-March 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. On December 30, 1999 the Company filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. On June 29, 2000 the NCUC approved the Company's
requests for disbursement of up to $28.4 million from the Company's expansion
fund for this project. The Company estimates that the cost of this project will
be approximately $31.4 million. The Madison County portion of the project was
completed at a cost of approximately $5.8 million and customers began receiving
service in July 2001.
On December 7, 1999 the NCUC issued an order approving SCANA's
acquisition of the Company. As specified in the NCUC order, the Company reduced
its rates by approximately $1 million in each of August 2000 and August 2001,
and agreed to a moratorium on general rate cases until August 2005. General rate
relief can be obtained during this period to recover costs associated with
materially 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 March 31, 2002 the fair value
of these swaps was not significant.
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 that the cost to remediate the sites would range 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 March 31, 2002
the Company has recorded a liability and associated regulatory asset of $9.0
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 Gas All Adjustments/ Consolidated
March 31, 2002 Distribution Other Eliminations Total
----------------------------------------------------------------------------
External Revenue $134 - - $134
Operating Income 38 n/a - 38
Segment Assets 1,202 $29 $(8) 1,223
----------------------------------------------------------------------------
Three months ended Gas All Adjustments/ Consolidated
March 31, 2001 Distribution Other Eliminations Total
----------------------------------------------------------------------------
External Revenue $228 - - $228
Operating Income 39 n/a - 39
Segment Assets 1,232 $29 $(25) 1,236
58
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
annual 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 three months ended March 31, 2002 and 2001 was as
follows:
Millions of dollars 2002 2001
- -----------------------------------------------------------------------------
Net income derived from continuing operations $20.8 $20.3
=============================================================================
The increase in net income from continuing operations reflects the
elimination of the amortization of the acquisition adjustment in the amount of
$3.3 million (see Note 1B of Notes to Condensed Consolidated Financial
Statements). The increase was partially offset by reduced margin, higher
operating expenses, and increased interest expense.
The nature of PSNC's business is seasonal. The quarters ending March 31
and December 31 are generally PSNC's most profitable quarters due to increased
demand for natural gas related to higher 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
Gas Distribution
Gas distribution sales margins for 2002 and 2001 were as follows:
Millions of dollars 2002 2001 Change % Change
-----------------------------------------------------------------------------
Operating revenues $133.9 $228.4 $(94.5) (41.4)%
Less: Cost of gas 67.4 160.6 (58.0)%
(93.2)
---------------------------------------------------------
Gross margin $ 66.5 $ 67.8 $ (1.9)%
(1.3)
=============================================================================
Gas distribution sales margin for the quarter ended March 31, 2002
decreased primarily as a result of lower natural gas usage and the effects of a
$1 million reduction in rates in August 2001 related to the acquisition of PSNC
by SCANA. The decrease in sales margin was partially offset by customer growth.
Operation and Maintenance Expenses
The $1.3 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 $3.3 million (see
Note 1B of Notes to Condensed Consolidated Financial Statements). The decrease
is partially offset by additions to plant.
Interest Expense
Interest expense increased $0.5 million over 2001 as a result of
increased borrowings. PSNC issued $150 million of medium-term notes on February
16, 2001. The proceeds from these borrowings were used to reduce short-term
debt.
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 March 31, 2002 was 2.3.
In late 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.)
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, 4 and 5 are not applicable.
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits
SCANA Corporation, South Carolina Electric & Gas Company and
Public Service Company of North Carolina, Incorporated:
Exhibits filed with this Quarterly Report on Form 10-Q are
listed in the following Exhibit Index. Certain of such exhibits
which have heretofore been filed with the Securities and
Exchange Commission and which are designated by reference to
their exhibit numbers in prior filings are hereby incorporated
herein by reference and made a part hereof.
B. Reports on Form 8-K during the first quarter 2002 were as follows:
SCANA Corporation:
Date of Report: January 23, 2002
Item reported: Item 7
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)
May 15, 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)
May 15, 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)
May 15, 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
2.01 X X Agreement and Plan of Merger, dated as of February
16, 1999 as amended and restated as of May 10,
1999, by and among Public Service Company of North
Carolina, Incorporated, SCANA Corporation, New Sub
I, Inc. and New Sub II, Inc. (Filed as Exhibit 2.1
to Registration Statement No. 333-78227 on Form
S-4)
3.01 X Restated Articles of Incorporation of SCANA as
adopted on April 26, 1989 (Filed as Exhibit 3-A to
Registration Statement No. 33-49145)
3.02 X Articles of Amendment of SCANA, dated April 27,
1995 (Filed as Exhibit 4-B to
Registration Statement No. 33-62421)
3.03 X Restated Articles of Incorporation of SCE&G, as
adopted on May 3, 2001 (Filed as Exhibit 3.01 to
Registration Statement No. 333-65460)
3.04 X Articles of Amendment of SCE&G dated May 22, 2001
(Filed as Exhibit 3.02 to
Registration Statement No. 333-65460)
3.05 X Articles of Correction of SCE&G dated June 1, 2001
(Filed as Exhibit 3.03 to
Registration Statement No. 333-65460)
3.06 X Articles of Amendment of SCE&G dated June 14, 2001
(Filed as Exhibit 3.04 to
Registration Statement No. 333-65460)
3.07 X Articles of Amendment of SCE&G dated August 30,
2001 (Filed as Exhibit 3.07 to Form 10-Q for the
quarter ended September 30, 2001)
3.08 X Articles of Incorporation of PSNC (formerly New
Sub II, Inc.) dated February 12, 1999 (Filed as
Exhibit 3.01 to Registration Statement No.
333-45206)
3.09 X Articles of Amendment of PSNC (formerly New Sub
II, Inc.) as adopted on February 10, 2001 (Filed
as Exhibit 3.02 to Registration Statement No.
333-45206)
3.10 X Articles of Correction of PSNC dated February 11,
2001 (Filed as Exhibit 3.03 to Registration
Statement No. 333-45206)
3.11 X Articles of Amendment of SCE&G dated March 13,
2002 (Filed as Exhibit 3.11 to Form 10-K for the
year ended December 31, 2001)
3.12 X Articles of Amendment of SCE&G dated May 9, 2002
(Filed herewith)
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
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
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EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
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 NatisBank of
Georgia, National Association (Filed as Exhibit
4-F to Registration Statement No. 33-49421)
- ------------
4.07 X X First Supplemental Indenture to Indenture
referred to in Exhibit 4.06 dated as
of June 1, 1993 (Filed as Exhibit 4-G to
Registration Statement No. 33-49421)
- ------------
4.08 X X Second Supplemental Indenture to Indenture
referred to in Exhibit 4.06 dated
as of June 15, 1993 (Filed as Exhibit 4-G to
Registration Statement No. 33-57955)
- ------------
4.09 X X Trust Agreement for SCE&G Trust I (Filed as
Exhibit 4.03 to Registration Statement No.
333-49960)
- ------------
4.10 X X Certificate of Trust of SCE&G Trust I (Filed as
Exhibit 4.04 to Registration
Statement No. 333-49960)
- ------------
4.11 X X Junior Subordinated Indenture for SCE&G Trust I
(Filed as Exhibit 4.05 to
Registration Statement No. 333-49960)
- ------------
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as
Exhibit 4.06 to Registration
Statement No. 333-49960)
- ------------
4.13 X X Amended and Restated Trust Agreement for SCE&G
Trust I (Filed as Exhibit 4.07
to Registration Statement No. 333-49960)
- ------------
4.14 X X Indenture dated as of January 1, 1996 between
PSNC and First Union National
Bank of North Carolina, as Trustee (Filed as
Exhibit 4.08 to Registration
Statement No. 333-45206)
- ------------
4.15 X X First Supplemental Indenture dated as of
January 1, 1996, between PSNC and
First Union National Bank of North Carolina,
as Trustee (Filed as Exhibit 4.09
to Registration Statement No. 333-45206)
- ------------
4.16 X X Second Supplemental Indenture dated as of
December 15, 1996 between PSNC and
First Union National Bank of North
Carolina, as Trustee (Filed as
Exhibit 4.10 to Registration
Statement No. 333-45206)
- ------------
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
4.17 X X Third Supplemental Indenture dated as of February
10, 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)
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4.19 X PSNC $150 million medium-term note issued February
16, 2001 (Filed as Exhibit 4.06 to Registration
Statement No. 333-68516)
- --------
10.01 X SCANA Executive Deferred Compensation Plan as
amended July 1, 2001 (Filed as Exhibit 10.01 to
Form 10-Q for the quarter ended September 30, 2001)
- --------
10.02 X SCANA Supplemental Executive
Retirement Plan as amended July
1, 2001 (Filed as Exhibit 10.02
to Form 10-Q for the quarter
ended September 30, 2001)
- --------
10.03 X SCANA Key Executive Severance
Benefits Plan as amended July 1,
2001 (Filed as Exhibit 10.03 to
Form 10-Q for the quarter ended
September 30, 2001)
- --------
10.03a X SCANA Supplementary Key
Executive Severance Benefits Plan
as amended July 1, 2001 (Filed as
Exhibit 10.03a to Form 10-Q for
the quarter ended September 30,
2001)
- --------
10.04 X SCANA Performance Share Plan as
amended and restated effective
January 1, 1998 (Filed as Exhibit
10 (e) to Registration Statement
No. 333-86803)
- --------
10.05 X SCANA Long-Term Equity Compensation Plan dated
January 2001 filed as Exhibit
4.04 to Registration Statement No. 333-37398)
- --------
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)