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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
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Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(a South Carolina Corporation)
1426 Main Street,
Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
(a South Carolina Corporation)
1426 Main Street,
Columbia, South Carolina 29201
(803) 217-9000
1-11429 Public Service Company of North
Carolina, Incorporated 56-2128483
(a South Carolina Corporation)
1426 Main Street,
Columbia, South Carolina 29201
(803) 217-9000
Indicate by check mark whether the registrants: (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the last practicable date.
Description of Shares Outstanding
Registrant Common Stock at July 31, 2001
SCANA Corporation Without Par Value 104,728,268
South Carolina Electric
& Gas Company Par Value $4.50 Per Share 40,296,1471
Public Service Company of
North Carolina, Incorporated Without Par Value 1,0001
1Held beneficially and of record by SCANA Corporation.
This combined Form 10-Q is separately filed by SCANA Corporation, South
Carolina Electric & Gas Company and Public Service Company of North Carolina,
Incorporated. Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no representation as
to information relating to the other companies.
Public Service Company of North Carolina, Incorporated meets the
conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and
therefore is filing this form with the reduced disclosure format allowed under
General Instruction H(2).
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INDEX
Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section...................................... 3
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2001
and December 31, 2000.......................................... 4
Condensed Consolidated Statements of Income and Retained
Earnings for the Periods Ended June 30, 2001 and 2000.......... 6
Condensed Consolidated Statements of Cash Flows for the
Periods Ended June 30, 2001 and 2000........................... 7
Notes to Condensed Consolidated Financial Statements........... 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk...... 23
South Carolina Electric & Gas Company Financial Section.................. 25
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2001
and December 31, 2000 ...................................... 26
Condensed Consolidated Statements of Income and Retained
Earnings for the Periods Ended June 30, 2001 and 2000....... 27
Condensed Consolidated Statements of Cash Flows for the
Periods Ended June 30, 2001 and 2000........................ 29
Notes to Condensed Consolidated Financial Statements.......... 30
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 34
Item 3. Quantitative and Qualitative Disclosures About Market Risk...... 38
Public Service Company of North Carolina, Incorporated Financial Section. 40
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30,
2001 and December 31, 2000 ................................. 41
Condensed Consolidated Statements of Income(Loss) and
Retained Earnings for the Periods Ended June 30,
2001 and 2000............................................... 42
Condensed Consolidated Statements of Cash Flows for
the Periods Ended June 30, 2001 and 2000.................... 43
Notes to Condensed Consolidated Financial Statements..................... 44
Item 2. Management's Narrative Analysis of Results of Operations......... 48
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................... 50
Item 4. Submission of Matters to a Vote of Security-Holders............. 50
Item 6. Exhibits and Reports on Form 8-K................................ 51
Signatures............................................................... 52
Exhibit Index............................................................ 55
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
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June 30, December 31,
Millions of dollars 2001 2000
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Assets
Utility Plant:
Electric $4,741 $4,747
Gas 1,445 1,435
Other 188 187
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Total 6,374 6,369
Less accumulated depreciation and amortization 2,292 2,212
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Total 4,082 4,157
Construction work in progress 426 261
Nuclear fuel, net of accumulated amortization 51 57
Acquisition adjustment, net of
accumulated amortization 467 474
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Utility Plant, Net 5,026 4,949
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Nonutility Property, net of accumulated depreciation 101 79
Investments 225 203
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- ------------------------------------------------------------------------------
Nonutility Property and Investments, Net 326 282
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Current Assets:
Cash and temporary investments 185 159
Receivables (net of allowance for
uncollectible accounts of $40 in
2001 and $31 in 2000) 461 699
Inventories (at average cost):
Fuel 151 107
Materials and supplies 57 56
Emission allowances 17 20
Prepayments 27 16
Investments 883 479
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Total Current Assets 1,781 1,536
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Deferred Debits:
Environmental 37 30
Nuclear plant decommissioning fund 75 72
Pension asset, net 216 196
Other regulatory assets 222 213
Other 165 142
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Total Deferred Debits 715 653
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Total $7,848 $7,420
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SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
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June 30, December 31,
Millions of dollars 2001 2000
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Capitalization and Liabilities
Stockholders' Investment:
Common Equity $2,304 $2,032
Preferred stock (Not subject to purchase or
sinking funds) 106 106
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Total Stockholders' Investment 2,410 2,138
Preferred Stock, net (Subject to purchase or
sinking funds) 10 10
SCE&G-Obligated Mandatorily Redeemable Preferred
Securities of SCE&G's Subsidiary Trust, SCE&G
Trust I, holding solely $50 million principal
amount of the 7.55% Junior Subordinated
Debentures of SCE&G, due 2027 50 50
Long-Term Debt, net 2,950 2,850
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Total Capitalization 5,420 5,048
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Current Liabilities:
Short-term borrowings 116 398
Current portion of long-term debt 438 41
Accounts payable 238 396
Customer deposits 21 25
Taxes accrued 11 54
Interest accrued 51 42
Dividends declared 34 32
Deferred income taxes, net 241 98
Other 20 25
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Total Current Liabilities 1,170 1,111
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Deferred Credits:
Deferred income taxes, net 729 721
Deferred investment tax credits 116 119
Reserve for nuclear plant decommissioning 75 72
Postretirement benefits 117 113
Other regulatory liabilities 94 75
Other 127 161
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Total Deferred Credits 1,258 1,261
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Total $7,848 $7,420
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See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Unaudited)
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Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars, except per share amount 2001 2000 2001 2000
- ------------------------------------------------------- -------------- --------------- --------------
Operating Revenues:
Electric $340 $320 $681 $614
Gas - Regulated 175 164 642 476
Gas - Nonregulated 225 178 736 394
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Total Operating Revenues 740 662 2,059 1,484
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Operating Expenses:
Fuel used in electric generation 68 72 135 143
Purchased power 39 11 87 17
Gas purchased for resale 333 278 1,148 657
Other operation and maintenance 122 120 251 229
Depreciation and amortization 56 53 112 108
Other taxes 29 29 59 58
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Total Operating Expenses 647 563 1,792 1,212
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Operating Income 93 99 267 272
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Other Income:
Other income, including allowance for
equity funds used during construction 18 8 31 17
Gain on sale of subsidiary assets - - 9 1
Gain on sale of investments 546 - 546 -
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- --------------------------------------------------------- -------------- --------------- --------------
Total Other Income 564 8 586 18
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Income Before Interest Charges, Income Taxes,
Preferred Stock Dividends and Cumulative
Effect of Accounting Change 657 107 853 290
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Interest Charges:
Interest expense on long-term debt, net 59 51 119 95
Other interest expense, net of allowance
for borrowed funds used during construction - 4 2 14
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Total Interest Charges, Net 59 55 121 109
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Income Before Income Taxes, Preferred Stock
Dividends and Cumulative Effect of
Accounting Change 598 52 732 181
Income Taxes 210 21 262 72
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Income Before Preferred Stock Dividends
and Cumulative Effect of Accounting Change 388 31 470 109
Preferred Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 2 2
1
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Income Before Cash Dividends on Preferred Stock
of Subsidiary and Cumulative Effect of
Accounting Change 387 30 468 107
Cash Dividends on Preferred Stock of
Subsidiary (At stated rates) 2 2 4 4
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Income Before Cumulative Effect of
Accounting Change 385 28 464 103
Cumulative Effect of Accounting Change,
net of taxes (Note 2) - - - 29
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Net Income 385 28 464 132
Retained Earnings at Beginning of Period 898 794 850 720
Common Stock Cash Dividends Declared (32) (30) (63) (60)
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Retained Earnings at End of Period $1,251 $792 $1,251 $792
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Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $3.67 $.27 $4.42 $.99
Cumulative Effect of Accounting Change, net of taxes - - - .28
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Basic and diluted earnings per share $3.67 $.27 $4.42 $1.27
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Weighted average shares outstanding (millions) 104.7 104.7 104.7 104.4
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See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
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Six Months Ended June 30,
Millions of dollars 2001 2000
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Cash Flows From Operating Activities:
Net income $464 $132
Adjustments to reconcile net income to net cash
provided from operating activities:
Cumulative effect of accounting change,
net of taxes - (29)
Depreciation and amortization 116 127
Amortization of nuclear fuel 6 10
Gain on sale of subsidiary assets and investments (555) (1)
Hedging activities (46) -
Undistributed earnings of affiliates, net (2) (1)
Preferred stock dividends of subsidiary 4 4
Allowance for funds used during construction (9) (3)
Over (under) collection, fuel adjustment clauses 2 11
Changes in certain assets and liabilities:
(Increase) decrease in receivables 234 33
(Increase) decrease in inventories (42) 36
(Increase) decrease in pension asset (20) (19)
(Increase) decrease in other regulatory
assets 3 19
Increase (decrease) in deferred income
taxes, net 220 16
Increase (decrease) in regulatory liabilities 5 2
Increase (decrease) in postretirement benefits 4 12
Increase (decrease) in accounts payable (158) (19)
Increase (decrease) in taxes accrued (43) (59)
Other, net (91) (45)
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Net Cash Provided From Operating Activities 92 226
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Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (183) (132)
Purchase of subsidiary, net of cash acquired - (212)
Proceeds from sale of subsidiary assets 24 -
Proceeds from sale of assets 2 1
Increase in nonutility property (25) (5)
Increase in investments (28) (17)
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Net Cash Used For Investing Activities 210) (365)
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Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 149 148
Issuance of notes and loans 648 699
Repayments and repurchases:
First Mortgage Bonds - (100)
Notes and loans (306) -
Other long-term debt - (2)
Common stock - (488)
Dividend payments:
Common stock (61) (64)
Preferred stock of subsidiary (4) (4)
Short-term borrowings, net (282) (91)
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Net Cash Provided From Financing Activities 144 98
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Net Increase (Decrease) In Cash and
Temporary Investments 26 (41)
Cash and Temporary Investments, January 1 159 116
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Cash and Temporary Investments, June 30 $185 $75
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Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest
of $5 for 2001 and $2 for 2000) $111 $95
- Income taxes 41 76
Noncash Investing and Financing Activities:
Unrealized gain (loss) on securities available
for sale, net of tax 255 111
In conjunction with the February 2000 acquisition of Public Service Company of
North Carolina, Incorporated, liabilities were
assumed as follows:
Fair value of assets acquired $1,177
Cash paid for capital stock (212)
Stock issued for consideration (488)
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Liabilities assumed $477
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See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2001
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in SCANA Corporation's (the Company)
Annual Report on Form 10-K for the year ended December 31, 2000. These are
interim financial statements, and due to the seasonality of the Company's
business, the amounts reported in the Condensed Consolidated Statements of
Income are not necessarily indicative of amounts expected for the year. In the
opinion of management, the information furnished herein reflects all
adjustments, all of a normal recurring nature except as described in Notes 2, 3
and 4, which are necessary for a fair statement of the results for the interim
periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This accounting standard requires
cost-based rate-regulated utilities to recognize in their financial
statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result the Company has
recorded, as of June 30, 2001, approximately $259 million and $94
million of regulatory assets and liabilities, respectively, including
amounts recorded for deferred income tax assets and liabilities of
approximately $140 million and $65 million, respectively. The electric
and gas regulatory assets of approximately $72 million and $47 million,
respectively, (excluding deferred income tax assets) are recoverable
through rates. In the future, as a result of deregulation or other
changes in the regulatory environment, the Company may no longer meet
the criteria for continued application of SFAS 71 and could be required
to write off its regulatory assets and liabilities. Such an event could
have a material adverse effect on the Company's results of operations in
the period the write-off would be recorded, but it is not expected that
cash flows or financial position would be materially affected.
B. Comprehensive Income
Comprehensive income includes net income and all other changes in equity
except those resulting from investments by and distributions to
stockholders. Comprehensive income(loss) of the Company totaled $104
million and $335 million for the three and six months ended June 30,
2001, respectively, and $(10) million and $21 million for the same
periods in 2000. Other comprehensive income includes unrealized
gains(losses) on securities available for sale of $(247) million and
$(99) million for the three and six months ended June 30, 2001,
respectively, and $184 million and $111 million for the same periods in
2000. Included in these amounts is a $291 million unrealized
gain associated with the Powertel, Inc. investment, which was realized
in net income on May 31, 2001. (See further discussion of the Powertel,
Inc. merger at Note 8.) Other comprehensive income also included
unrealized losses on hedging activities of $34 million and $30 million
for the three and six months ended June 30, 2001, respectively.
Accumulated other comprehensive income of the Company totaled $10
million and $139 million as of June 30, 2001 and December 31, 2000,
respectively.
C. New Accounting Standards
On January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. See Note 7
for a discussion of the impact of the Company's adoption of SFAS 133.
In June 2001 the Financial Accounting Standards Board approved the
issuance of three new accounting standards. SFAS 141, "Business
Combinations," requires that all business combinations be accounted for
using the purchase method of accounting. SFAS 141 applies to all
business combinations initiated after June 30, 2001, and is not
expected to have any impact on the Company's results of operations,
cash flows or financial position.
SFAS 142, "Goodwill and Other Intangible Assets," requires that
goodwill not be amortized but instead be tested for impairment at least
annually at the reporting unit level. A reporting unit is the same
level as, or one level below, an operating segment. The Company will
adopt SFAS 142 effective January 1, 2002. The impact SFAS 142 may have
on the Company's results of operations, cash flows and financial
position has not been determined but could be material.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company
will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may
have on the Company's results of operations, cash flows and financial
position has not been determined.
D. Stock Option Plan
On April 27, 2000 the Company adopted the SCANA Corporation Long-Term
Equity Compensation Plan (the Plan). Under the Plan, certain employees
and non-employee directors may receive nonqualified stock options and
other forms of equity compensation. The Company accounts for this
equity-based compensation under Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB 25), and related
interpretations. In addition the Company has adopted the disclosure
provisions of SFAS 123, "Accounting for Stock-Based Compensation." As
of June 30, 2001 options to acquire approximately 848,000 shares of
SCANA common stock have been granted at strike prices equal to or
greater than market prices on the dates of issuance. Therefore no
compensation expense has been recorded.
E. Earnings Per Share
Earnings per share amounts have been computed in accordance with SFAS
128, "Earnings Per Share." Under SFAS 128, basic earnings per share are
computed by dividing net income by the weighted average number of
common shares outstanding for the period. Diluted earnings per share
are computed as net income divided by the weighted average number of
shares of common stock outstanding during the period after giving
effect to securities considered to be dilutive potential common stock.
The Company uses the treasury stock method in determining total
dilutive potential common stock.
F. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2001.
2. Cumulative Effect of Accounting Change
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues associated with its regulated utility operations
from cycle billing to full accrual. The cumulative effect of this
change was $29 million, net of tax. Accruing unbilled revenues more
closely matches revenues and expenses. Unbilled revenues represent the
estimated amount customers will be charged for service rendered but not
yet billed as of the end of the accounting period.
3. ACQUISITION
On February 10, 2000 the Company completed its acquisition of Public
Service Company of North Carolina, Inc. (PSNC) in a business
combination accounted for as a purchase. PSNC became a wholly owned
subsidiary of the Company. PSNC is a public utility engaged primarily
in transporting, distributing and selling natural gas to approximately
362,000 residential, commercial and industrial customers in 25 of its
28 franchised counties in North Carolina. Pursuant to the Agreement and
Plan of Merger, PSNC shareholders were paid approximately $212 million
in cash and 17.4 million shares of SCANA common stock valued at
approximately $488 million. In connection with the acquisition, 16.3
million shares of SCANA common stock were repurchased for approximately
$488 million. The results of operations of PSNC are included in the
accompanying financial statements as of January 1, 2000, the effective
date of acquisition. The total cost of the acquisition was
approximately $700 million, which exceeded the fair value of the net
assets acquired by approximately $466 million. The excess is being
amortized over 35 years on a straight-line basis.
4. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company
A. On April 24, 2001 the Public Service Commission of South Carolina
(PSC) approved South Carolina Electric & Gas Company's (SCE&G)
request to increase the fuel component of rates charged to electric
customers from 1.330 cents per kilowatt-hour to 1.579 cents per
kilowatt-hour. The increase reflects higher fuel costs projected
for the period May 2001 through April 2002. The increase also
provides recovery over a two-year period of under-collected actual
fuel costs through April 2001, including short-term purchased power
costs necessitated by outages at two of SCE&G's base load
generating plants in winter 2000-2001. The new rates were effective
as of the first billing cycle in May 2001.
B. On July 20, 2000 the PSC approved SCE&G's request for an
out-of-period adjustment to increase the cost of gas component of
its rates for natural gas service from 54.334 cents per therm to
68.835 cents per therm, effective with the first billing cycle in
August 2000. As part of its regularly scheduled annual review of
gas costs, the PSC issued an order on November 9, 2000 which
further increased the cost of gas component to 78.151 cents per
therm, effective with the first billing cycle in November 2000. On
December 21, 2000 the PSC issued an order approving SCE&G's request
for another out-of-period adjustment to increase the cost of gas
component to 99.340 cents per therm, effective with the first
billing cycle in January 2001. On March 9, 2001 the PSC issued an
order granting SCE&G's request to reduce the cost of gas component
to 79.340 cents per therm, effective with the first billing cycle
in March 2001.
C. On July 5, 2000 the PSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were
effective retroactively to January 1, 2000 and resulted in a
reduction in annual depreciation expense of approximately $2.9
million. The retroactive effect was recorded in the second quarter
of 2000.
D. On September 14, 1999 the PSC approved an accelerated capital
recovery plan for SCE&G's Cope Generating Station. The plan was
implemented beginning January 1, 2000 for a three-year period. The
PSC approved an accelerated capital recovery methodology wherein
SCE&G may increase depreciation of its Cope Generating Station in
excess of amounts that would be recorded based upon currently
approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of
revenues and operating expenses, not to exceed $36 million annually
without the approval of the PSC. Any unused portion of the $36
million in any given year may be carried forward for possible use
in the following year. As of June 30, 2001 no accelerated
depreciation has been recorded. The accelerated capital recovery
plan will be accomplished through existing customer rates.
E. On January 9, 1996 the PSC issued an order granting SCE&G an
increase in retail electric rates which was fully implemented by
January 1997. The PSC authorized a return on common equity of 12.0
percent. The PSC also approved establishment of a Storm Damage
Reserve Account capped at $50 million to be collected through rates
over a ten-year period. Additionally, the PSC approved accelerated
amortization of a significant portion of SCE&G's electric
regulatory assets (excluding deferred income tax assets) and the
remaining transition obligation for postretirement benefits other
than pensions, which enabled SCE&G to recover the balances as of
the end of the year 2000.
F. In 1994 the PSC issued an order approving SCE&G's request to
recover through a billing surcharge to its gas customers the costs
of environmental cleanup at the sites of former manufactured gas
plants (MGPs). The billing surcharge is subject to annual review
and provides for the recovery of substantially all actual and
projected site assessment and cleanup costs and environmental
claims settlements for SCE&G's gas operations that had previously
been deferred. In November 2000, as a result of the annual review,
the PSC approved SCE&G's request to maintain the billing surcharge
of $.011 per therm that provides for the recovery of the balance
remaining at June 30, 2001 of $26.3 million.
Public Service Company of North Carolina, Incorporated
G. On April 6, 2000 the North Carolina Utilities Commission (NCUC)
issued an order permanently approving PSNC's request to establish
its commodity cost of gas for large commercial and industrial
customers on the basis of market prices for natural gas. The NCUC
previously allowed PSNC use of this mechanism on a trial basis. This
mechanism allows PSNC to collect from its customers amounts
approximating the amounts paid for natural gas.
H. A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate
pipeline transporters, provides financing for expansion into areas
that otherwise would not be economically feasible to serve. On
December 30, 1999 PSNC filed an application with the NCUC to extend
natural gas service to Madison, Jackson and Swain Counties, North
Carolina. Pursuant to state statutes, the NCUC required PSNC to
forfeit its exclusive franchises to serve six counties in western
North Carolina effective January 31, 2000 because these counties
were not receiving any natural gas service. Madison, Jackson and
Swain Counties were included in the forfeiture order. On June 29,
2000 the NCUC approved PSNC's requests for reinstatement of its
exclusive franchises for Madison, Jackson and Swain Counties and
disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be
approximately $31.4 million. The Madison County portion of the
project was completed at a cost of approximately $4.8 million and
customers began receiving service in July 2001.
I. On December 7, 1999 the NCUC issued an order approving SCANA's
acquisition of PSNC. As specified in the NCUC order, PSNC reduced
its rates by approximately $1 million in each of August 2000 and
August 2001, and has agreed to a moratorium on general rate cases
until August 2005. General rate relief can be obtained during this
period to recover costs associated with materially adverse
governmental actions and force majeure events.
5. LONG-TERM DEBT
On January 24, 2001 SCANA issued $202 million two-year floating rate
notes maturing on January 24, 2003. The interest rate is reset quarterly
based on three-month LIBOR plus 110 basis points. Also on January 24,
2001 SCE&G issued $150 million First Mortgage Bonds having an annual
interest rate of 6.70 percent and maturing on February 1, 2011. On
February 16, 2001 PSNC issued $150 million of medium-term notes having
an annual interest rate of 6.625 percent and maturing on February 15,
2011. The proceeds from these borrowings were used to reduce short-term
debt and for general corporate purposes. In addition, on May 9, 2001
SCANA issued $300 million medium-term notes maturing May 15, 2011 and
bearing a fixed interest rate of 6.875 percent. The proceeds were used
to refinance $300 million bank notes originally issued to consummate
SCANA's acquisition of PSNC.
6. RETAINED EARNINGS
The Company's Restated Articles of Incorporation do not limit the
dividends that may be payable on its common stock. However, the Restated
Articles of Incorporation of SCE&G and the Indenture underlying its
First and Refunding Mortgage Bonds contain provisions that, under
certain circumstances, could limit the payment of cash dividends on its
common stock.
In addition, with respect to hydroelectric projects, the Federal Power
Act requires the appropriation of a portion
of certain earnings therefrom. At June 30, 2001 approximately $34.8
million of retained earnings were restricted by this requirement as to
payment of cash dividends on SCE&G's common stock.
7. FINANCIAL INSTRUMENTS
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. SFAS 133
requires the Company to recognize all derivative instruments as either
assets or liabilities in the statement of financial position and to
measure those instruments at fair value. SFAS 133 further provides that
changes in the fair value of derivative instruments are either
recognized in earnings or reported as a component of other comprehensive
income, depending upon the intended use of the derivative and the
resulting designation.
The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of different types.
Instruments designated as cash flow hedges are used to hedge risks
associated with fixed price obligations in a volatile price market and
risks associated with price differentials at different delivery
locations. The basic types of financial instruments utilized are
exchange-traded instruments, such as NYMEX futures contracts or options
and over-the-counter instruments such as swaps, which are typically
offered by energy and financial institutions. These instruments do not
constitute investments independent of the hedged exposures.
Risk limits are established to control the level of market, credit,
liquidity and operational/administrative risks assumed by the Company.
The Company's Board of Directors has delegated the authority for setting
market risk limits to the Risk Management Committee, which is comprised
of members of senior management, the Company's Controller, the Senior
Vice President of South Carolina Pipeline Corporation and the President
of SCANA Energy Marketing, Inc. The Risk Management Committee provides
assurance to the Board of Directors with regard to compliance with risk
management policies and brings to the Board's attention any areas of
concern. Written policies define the physical and financial transactions
that are prohibited as well as the authorization requirements for
transactions that are allowed.
As a result of adopting SFAS 133, the Company recorded a credit of
approximately $23.0 million, net of tax, as the effect of a change in
accounting principle (transition adjustment) to other comprehensive
income on January 1, 2001. This amount represents the reclassification
of unrealized gains that were deferred and reported as liabilities at
December 31, 2000. All gains/losses related to qualifying cash flow
hedges so reflected in other comprehensive income will be reclassified
to earnings at the time the hedged transaction affects earnings.
The Company recognized income(loss) of approximately $(0.3) million and
$4.6 million, net of tax, as a result of qualifying cash flow hedges
whose hedged transactions occurred during the three and six months ended
June 30, 2001, respectively.
In May 2001 the Company entered into an interest rate swap agreement
whereby the Company pays variable rate and receives fixed rate interest
payments on a notional amount of $300 million. This swap is designated
as a fair value hedge of the $300 million medium-term notes also issued
in May. At June 30, 2001 the estimated fair value of this swap was $0.3
million.
8. INVESTMENTS IN EQUITY SECURITIES
At June 30, 2001 SCANA Communications Holdings, Inc. (SCH), a wholly
owned, indirect subsidiary of SCANA, held the following investments:
o SCH owns approximately 39.3 million ordinary shares of Deutsche
Telekom AG (DT), a European telecommunications carrier. These
shares were received in exchange for the approximately 14.9
million shares of Powertel, Inc. (Powertel) SCH owned prior to
DT's acquisition of Powertel in May 2001. SCH recorded a
non-cash, after-tax gain of $354.4 million as a result of the
exchange. SCH's investment in DT is approximately $798.0 million.
DT ordinary shares closed at $22.45 per share on June 30, 2001,
resulting in a pre-tax unrealized holding gain of $84.5 million.
Accumulated other comprehensive income includes the after-tax
amount of unrealized holding gains and losses on ordinary shares.
o ITC Holding Company, Inc. (ITC) holds ownership interests in
several Southeastern communications companies. SCH owns
approximately 3.1 million common shares, 645,153 series A
convertible preferred shares, and 133,664 series B convertible
preferred shares of ITC. These investments cost approximately
$5.8 million, $7.2 million, and $4.0 million, respectively. The
market values of these investments are not readily determinable.
o ITC^DeltaCom, Inc. (ITCD), an affiliate of ITC, is a fiber optic
telecommunications provider. SCH owns approximately 5.1 million
common shares of ITCD at a cost of approximately $43.0 million.
ITCD common stock closed on NASDAQ at $4.00 per share on June 30,
2001, resulting in a pre-tax unrealized holding loss of $21.9
million. In addition, SCH owns 1,480,771 shares of series A
preferred stock of ITCD at a cost of approximately $11.2 million.
Series A preferred shares become convertible in March 2002 into
2,961,542 shares of ITCD common stock. The market value of series
A preferred stock of ITCD is not readily determinable. However,
as converted, the market value of the underlying common stock for
the series A preferred stock was approximately $11.8 million at
June 30, 2001, reflecting an unrealized pre-tax holding gain of
$0.6 million. Accumulated other comprehensive income includes the
after-tax amount of all unrealized holding gains and losses on
common shares and preferred shares convertible within 12 months.
o Knology, Inc. (Knology), an affiliate of ITC, is a broad-band
service provider of cable television, telephone and internet
services. SCH owns $71,050,000 face amount of 11.875 percent
Senior Discount Notes due 2007 of Knology Broadband, Inc., a
wholly-owned subsidiary of Knology. The Senior Discount Notes
have a book basis at June 30, 2001 of approximately $61.3
million. In addition, SCH owns approximately 7.2 million shares
of Knology series A convertible preferred stock with a cost basis
of approximately $5.0 million and warrants to purchase
approximately 0.2 million shares of series A convertible
preferred stock. On January 12, 2001 SCH invested $25.0 million
for approximately 8.3 million shares of series C convertible
preferred stock of Knology. The market value of these investments
is not readily determinable.
In addition, the Company purchased 5,000 shares of ITCD series B
cumulative convertible preferred stock and a warrant to purchase up to
approximately 263,158 shares of ITCD common stock in May 2001 at a
cost of $5.0 million. These series B preferred shares are convertible
at any time into 877,193 shares of ITCD Common Stock. The market value
of this investment is not readily determinable. However, as converted,
the market value of the underlying common stock for the series B
preferred stock was approximately $3.5 million at June 30, 2001,
reflecting an unrealized pre-tax holding loss of $1.5 million.
Accumulated other comprehensive income includes the after-tax amount
of this unrealized holding loss.
9. CONTINGENCIES
With respect to commitments at June 30, 2001, reference is made to Note
13 of Notes to Consolidated Financial Statements appearing in the
Company's Annual Report on Form 10-K for the year ended December 31,
2000. Contingencies at June 30, 2001 include the following:
A. Lake Murray Dam Reinforcement
On October 15, 1999 the Federal Energy Regulatory Commission (FERC)
notified SCE&G of its agreement with SCE&G's plan to reinforce Lake
Murray Dam in order to maintain the lake in case of an extreme
earthquake. SCE&G and FERC have been discussing possible reinforcement
alternatives for the dam over the past several years as part of SCE&G's
ongoing hydroelectric operating license with FERC. The cost and
completion date of this project will depend on the reinforcement
alternative ultimately approved by FERC; however, it is possible that
the costs could range up to $300 million with completion dates ranging
from 2004 to 2006. Although any costs incurred by SCE&G are expected to
be recoverable through electric rates, SCE&G also is exploring
alternative sources of funding.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public
liability for a nuclear incident, currently establishes the liability
limit for third-party claims associated with any nuclear incident at
$9.5 billion. Each reactor licensee is currently liable for up to $88.1
million per reactor owned for each nuclear incident occurring at any
reactor in the United States, provided that not more than $10 million of
the liability per reactor would be assessed per year. SCE&G's maximum
assessment, based on its two-thirds ownership of V. C. Summer Nuclear
Station (Summer Station), would be approximately $58.7 million per
incident, but not more than $6.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of the
South Carolina Public Service Authority) with Nuclear Electric Insurance
Limited. The policies, covering the nuclear facility for property
damage, excess property damage and outage costs, permit assessments
under certain conditions to cover insurer's losses. Based on the current
annual premium, SCE&G's portion of the retrospective premium assessment
would not exceed $8.1 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and expenses
arising from a nuclear incident at Summer Station exceed the policy
limits of insurance, or to the extent such insurance becomes unavailable
in the future, and to the extent that SCE&G's rates would not recover
the cost of any purchased replacement power, SCE&G will retain the risk
of loss as a self-insurer. SCE&G has no reason to anticipate a serious
nuclear incident at Summer Station. If such an incident were to occur,
it could have a material adverse impact on the Company's results of
operations, cash flows and financial position.
C. Environmental
The Company maintains an environmental assessment program to identify
and assess current and former operations sites that could require
environmental cleanup. As site assessments are initiated, estimates are
made of the amount of expenditures, if any, deemed necessary to
investigate and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual expenditures
could differ significantly from the original estimates. Amounts
estimated and accrued to date for site assessments and cleanup relate
primarily to regulated operations.
For SCE&G, such amounts are deferred and amortized with recovery
provided through rates. Deferred amounts, net of amounts previously
recovered through rates and insurance settlements, totaled $26.3 million
at June 30, 2001. The deferral includes the estimated costs associated
with the following matters.
o In September 1992 the Environmental Protection Agency (EPA)
notified SCE&G, the City of Charleston and the Charleston Housing
Authority of their potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South
Carolina. This site encompasses approximately 30 acres and
includes properties which were locations for industrial
operations, including a wood preserving (creosote) plant, one of
SCE&G's decommissioned MGPs, properties owned by the National
Park Service and the City of Charleston and private properties.
The site has not been placed on the National Priorities List, but
may be added in the future. The Potentially Responsible Parties
(PRPs) negotiated an administrative order by consent for the
conduct of a Remedial Investigation/Feasibility Study and a
corresponding Scope of Work. Field work began in November 1993,
and the EPA approved a Remedial Investigation Report in February
1997 and a Feasibility Study Report in June 1998. In July 1998
the EPA approved SCE&G's Removal Action Work Plan for soil
excavation. SCE&G completed Phase One of the Removal Action Work
Plan in 1998 at a cost of approximately $1.5 million. Phase Two,
which cost approximately $3.5 million, included excavation and
installation of several permanent barriers to mitigate coal tar
seepage. In September 1998 a Record of Decision was issued which
sets forth the EPA's view of the extent of each PRP's
responsibility for site contamination and the level to which the
site must be remediated. SCE&G estimates that the Record of
Decision will result in costs of approximately $16.5 million, of
which approximately $1.6 million remains. In January 1999 the EPA
issued a Unilateral Administrative Order for Remedial Design and
Remedial Action directing SCE&G to design and carry out a plan of
remediation for the Calhoun Park site. SCE&G submitted a
Comprehensive Remedial Design Work Plan (RDWP) in December 1999
and proceeded with implementation pending agency approval. The
RDWP was approved by the EPA in July 2000, and its implementation
continues.
In September 2000, SCE&G was notified by the South Carolina
Department of Health and Environmental Control (DHEC) that
benzene contamination was detected in the intermediate aquifer
on surrounding properties to the Calhoun Park Area site. The
EPA has required that SCE&G conduct a focused Remedial
Investigation/Feasibility Study on the intermediate aquifer.
The EPA expects to issue a second Record of Decision dealing
with the intermediate aquifer in September 2001. Intermediate
groundwater investigation and cleanup is expected to cost
approximately $4.7 million.
o SCE&G owns three other decommissioned MGP sites in South Carolina
which contain residues of by-product chemicals. For the site
located in Sumter, effective September 15, 1998, SCE&G entered
into a Remedial Action Plan Contract with DHEC pursuant to which
it agreed to undertake a full site investigation and remediation
under the oversight of DHEC. Site investigation, characterization
and remediation are proceeding according to schedule. Excavation
at the Sumter MGP site was completed in May 2001 as part of an
Interim Removal Action. Further work may be required at the
discretion of DHEC. Upon successful implementation of a site
remedy, DHEC will give SCE&G a Certificate of Completion and a
covenant not to sue. For the site located in Florence SCE&G
entered into a similar Remedial Action Plan Contract with DHEC in
September 2000. SCE&G is continuing to investigate the remaining
site in Columbia, and is monitoring the nature and extent of
residual contamination.
In addition, PSNC owns, or has owned, all or portions of seven sites in
North Carolina on which MGPs were formerly operated. Intrusive
investigation (including drilling, sampling and analysis) has begun at
two sites and the remaining sites have been evaluated using historical
records and observations of current site conditions. These evaluations
have revealed that MGP residuals are present or suspected at several of
the sites. The North Carolina Department of Environment and Natural
Resources (DENR) has recommended that no further action be taken with
respect to one site. Excavation at the Raleigh MGP site was completed in
March 2001 as part of an Interim Removal Action. Further work may be
required at the discretion of DENR. Work at the Durham MGP site began in
May 2001 under a DENR-approved Phase II Workplan. An environmental due
diligence review of PSNC conducted in February 1999 estimated that the
cost to remediate the remaining sites would range between $11.3 million
and $21.9 million. During the second quarter of 2000, the review was
finalized and the estimated liability was recorded. PSNC is unable to
determine the rate at which costs may be incurred over this time period.
The estimated cost range has not been discounted to present value. PSNC's
associated actual costs for these sites will depend on a number of
factors, such as actual site conditions, third-party claims and
recoveries from other PRPs. A May 1993 order by the NCUC authorized
deferral accounting for all costs associated with the investigation and
remediation of MGP sites. As of June 30, 2001 PSNC has recorded a
liability and associated regulatory asset of $9.2 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 not material. Management intends to request recovery of
additional MGP clean-up costs not recovered from other PRPs in future
rate case filings, and believes that all costs incurred will be
recoverable in gas rates.
10. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The Company
uses operating income to measure profitability for its Electric Operations and
Gas Distribution segments. Therefore, net income is not allocated to these
segments. The Company uses net income to measure profitability for its Retail
Gas Marketing and Energy Marketing segments. Affiliate revenue is derived from
transactions between reportable segments as well as transactions between
separate legal entities that are combined into the same reportable segment.
Accumulated depreciation is not assignable to Electric Operations and Gas
Distribution segments.
Disclosure of Reportable Segments
(Millions of dollars)
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------
Three months ended Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
June 30, 2001 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------
External Customer Revenue 340 125 50 121 104 - - 740
Intersegment Revenue 133 - 47 - - - (180) -
Operating Income (Loss) 94 (7) 4 n/a n/a - 2 93
Net Income (Loss) n/a n/a 2 (5) 6 346 36 385
Segment Assets 4,790 1,606 288 114 126 1,453 (529) 7,848
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------
Six months ended Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
June 30, 2001 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------
External Customer Revenue 681 510 132 384 352 - - 2,059
Intersegment Revenue 272 1 166 - - - (439) -
Operating Income 191 53 4 n/a n/a - 19 267
Net Income n/a n/a 1 7 5 337 114 464
Segment Assets 4,790 1,606 288 114 126 1,453 (529) 7,848
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------
Three months ended Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
June 30, 2000 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------
External Customer Revenue 320 106 58 92 86 - - 662
Intersegment Revenue 139 1 39 - - - (179) -
Operating Income (Loss) 102 (5) 8 n/a n/a - (6) 99
Net Income (Loss) n/a n/a 4 9 (12) (13) 40 28
Segment Assets 4,820 1,518 246 44 113 1,089 (819) 7,011
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- --------------- --------------
Six months ended Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
June 30, 2000 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- ------------------------- ----------- ------------ -------------- ----------- ------------ ---------- --------------- --------------
External Customer Revenue 614 361 115 227 167 - - 1,484
Intersegment Revenue 216 1 101 - 2 - (320) -
Operating Income 193 54 16 na na - 9 272
Net Income (Loss) n/a n/a 8 9 (1) (25) 1411 132
Segment Assets 4,820 1,518 246 44 113 1,089 (819) 7,011
1 Includes cumulative effect of accounting change (See Note 2).
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- --------------------------------------------------------------------------------
SCANA CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations
appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for
the year ended December 31, 2000.
Statements included in this discussion and analysis (or elsewhere in
this quarterly report) which are not statements of historical fact are intended
to be, and are hereby identified as, "forward-looking statements" for purposes
of the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, (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 and (12) the other risks and uncertainties described
from time to time in the Company's periodic reports filed with the Securities
and Exchange Commission. The Company disclaims any obligation to update any
forward-looking statements.
LIQUIDITY AND CAPITAL RESOURCES
SCANA Energy, the Company's non-regulated retail gas division in
Georgia, has maintained its position as the second largest marketer in Georgia,
with an approximate 27 percent market share. SCANA Energy lost approximately
$2.5 million or $.03 per share in the quarter ended June 30, 2001 which
approximated the loss for the corresponding period in 2000. See additional
discussion at Results of Operations. Due to record high wholesale natural gas
prices and cold winter temperatures, the Georgia Public Service Commission
(GPSC) adopted emergency rules which prohibited gas marketers from disconnecting
service to residential customers for non-payment from mid-January through March
2001. Customers also were permitted to switch marketers without first paying
outstanding balances owed to their previous provider. As a result of the GPSC
action, SCANA Energy increased its allowance for uncollectible accounts in the
first quarter 2001 and has implemented more stringent credit policies.
On October 15, 1999 the Federal Energy Regulatory Commission (FERC)
notified South Carolina Electric & Gas Company (SCE&G) of its agreement with
SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case
of an extreme earthquake. SCE&G and FERC have been discussing possible
reinforcement alternatives for the dam over the past several years as part of
SCE&G's ongoing hydroelectric operating license with FERC. The cost and
completion date of this project will depend on the reinforcement alternative
ultimately approved by FERC; however, it is possible that the costs could range
up to $300 million with completion dates ranging from 2004 to 2006. Although any
costs incurred by SCE&G are expected to be recoverable through electric rates,
SCE&G also is exploring alternative sources of funding.
On February 9, 2000FERC issued FERC Order 2000. The Order requires
utilities which operate electric transmission systems to submit plans for the
possible formation of a regional transmission organization (RTO). In October
2000 the Company and two other southeastern electric utilities filed a joint
request with FERC to establish GridSouth Transco, LLC (GridSouth). FERC gave
provisional approval to GridSouth in March 2001. When operational, GridSouth
will function as an independent regional transmission company. In July 2001 FERC
ordered mediation talks to take place between the utilities forming GridSouth
and certain groups that have proposed other RTOs. These talks are being mediated
by an administrative law judge, with a stated goal of FERC being the formation
of a single RTO in the Southeast.
In March 2001 V. C. Summer Nuclear Station returned to service. It had
been taken out of service on October 7, 2000 for a planned maintenance and
refueling outage. During initial inspection activities, plant personnel
discovered a small leak coming from a hole in a weld in a primary coolant system
pipe. Repairs were completed and the integrity of the new welds was verified
through extensive testing. The PSC has approved recovery of the cost of
replacement power through SCE&G's electric fuel adjustment clause (see Note 4A
of Notes to Condensed Consolidated Financial Statements). The Nuclear Regulatory
Commission was closely involved throughout this process and approved SCE&G's
actions to repair the crack, as well as the restart schedule. SCE&G will
continue to monitor primary coolant system pipes during the next outage,
scheduled for Spring of 2002.
In March 2001 the Company completed the sale of its home security and
alarm monitoring division (SCANA Security). The sale, valued at approximately
$24.5 million, resulted in a one-time gain of approximately $.04 per share in
the first quarter 2001 (see Results of Operations).
In April 2001 SCE&G announced plans to construct a 620 megawatt combined
cycle natural gas-fueled power plant in Jasper County, South Carolina, to supply
electricity to its South Carolina customers. The proposed generation facility is
estimated to cost between $250 million and $300 million. Construction is
expected to begin in the Summer of 2002 and is expected to be completed in the
Summer of 2004.
In April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
returned to service. It had been taken out of service in January 2001 due to an
electrical ground in the generator. The PSC has approved recovery of the cost of
replacement power through SCE&G's electric fuel adjustment clause (see Note 4A
of Notes to Condensed Consolidated Financial Statements).
In June 2001 SCANA Communications, Inc. (SCI) agreed to subcontract the
operation and maintenance of its 800 megahertz radio service network to Motorola
for the period July 1, 2001 through March 31, 2002. After March 31, 2002 SCI has
the option to sell the network to Motorola.
In June 2001 South Carolina Pipeline Corporation (SCPC) announced that
it will petition The Public Service Commission of South Carolina (PSC) to allow
SCPC to convert from a closed system to an open-access transportation-only
system. Under an open system customers would be required to secure their own gas
supplies and transportation services. SCPC plans to file the petition in the
fall of 2001 and seek implementation in 2002.
In July 2001 the Company announced the formation of SCG Pipeline, Inc.,
a wholly owned subsidiary that will engage in the transportation of natural gas
in Georgia and South Carolina. SCG Pipeline will transport natural gas from
interconnections with Southern Natural Gas and Southern LNG's Elba Island
liquefied natural gas import terminal near Savannah, Georgia. The Company is
currently evaluating potential pipeline routes for an end point in Jasper
County, South Carolina. SCG Pipeline plans to file for FERC certification in the
fall of 2001. The proposed service date for the pipeline is November 2003. In
addition SCPC announced plans to extend its existing facilities to interconnect
with the proposed pipeline to gain access to additional supplies of natural gas.
The following table summarizes how the Company generated and used funds for
property additions and construction expenditures during the six months ended
June 30, 2001 and 2000:
- --------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2001 2000
- ------------------------------------------------------------------- ------------
Net cash provided from operating activities $92 $226
Net cash provided from financing activities 144 98
Cash provided from sale of subsidiary assets 24 -
Cash provided from sale of assets 2 1
Cash and temporary investments available at
the beginning of the period 159 116
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Net cash available for property additions
and construction expenditures $421 $441
================================================================================
Funds used for purchase of subsidiary - $212
Funds used for utility property
additions and construction expenditures,
net of noncash allowance for funds used
during construction $183 $132
Funds used for nonutility property additions $25 $5
============================================================= ==================
The Company's electric and natural gas businesses are seasonal in nature,
with the primary demand for electricity being experienced during summer and
winter and the primary demand for natural gas being experienced during winter.
As a result of the significant increase during early 2001 and the latter half of
2000 in the cost to the Company of natural gas and the colder than normal
weather experienced during winter 2000-2001, the Company experienced significant
increases in its working capital requirements, contributing to the need for the
financings by SCANA and PSNC in early 2001as described below.
On January 24, 2001 SCANA issued $202 million two-year floating rate
notes maturing on January 24, 2003. The interest rate is reset quarterly based
on three-month LIBOR plus 110 basis points. Also on January 24, 2001 SCE&G
issued $150 million First Mortgage Bonds having an annual interest rate of 6.70
percent and maturing on February 1, 2011. On February 16, 2001 PSNC issued $150
million of medium-term notes having an annual interest rate of 6.625 percent and
maturing on February 15, 2011. The proceeds from these borrowings were used to
reduce short-term debt and for general corporate purposes.
In addition, on May 9, 2001 SCANA issued $300 million medium-term notes
maturing May 15, 2011 and bearing a fixed interest rate of 6.875 percent. SCANA
also entered into an interest rate swap agreement to pay variable rate and
receive fixed rate interest payments. This swap is designated as a fair value
hedge on the medium-term notes. The proceeds from the issuance of the
medium-term notes were used to refinance $300 million of bank notes originally
issued to consummate SCANA's acquisition of PSNC.
The Company anticipates that the remainder of its 2001 cash requirements
will be met through internally generated funds and the incurrence of additional
short-term and long-term indebtedness. Sales of additional equity securities may
also occur. The Company expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the next 12 months and for
the foreseeable future. The Company's ratio of earnings to fixed charges for the
12 months ended June 30, 2001 was 2.50.
Environmental Matters
For information on environmental matters see Note 9C "Contingencies -
Environmental" of Notes To Condensed Consolidated Financial Statements appearing
in this Quarterly Report on Form 10-Q.
Investments in Equity Securities
The Company and SCANA Communications Holdings, Inc. (SCH), a wholly
owned, indirect subsidiary of SCANA, hold investments in several
telecommunications companies (described in Note 8 "Investments in Equity
Securities" of Notes to Condensed Consolidated Financial Statements appearing in
this Quarterly Report on Form 10-Q). As a result of Deutsche Telekom AG's (DT)
acquisition of Powertel, Inc. (Powertel) on May 31, 2001, SCH's investment in
Powertel was exchanged for approximately 39.3 million ordinary shares of DT. SCH
may not sell or transfer these ordinary shares until August 31, 2001, at which
time 40% may be sold or transferred . After November 30, 2001 SCH may sell or
transfer all of its DT shares. The Company intends to monetize SCH's investment
in DT in an appropriate and timely manner and to use the proceeds to reduce
outstanding debt and for potential future investments.
RESULTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2001
AS COMPARED TO THE CORRESPONDING PERIODS IN 2000
Earnings and Dividends
Earnings per share of common stock for the three and six months ended
June 30, 2001 and 2000 were as follows:
- --------------------------------------------------------------------------------
Three Months Ended Six Months Ended
2001 2000 2001 2000
- --------------------------------------------------------------------------------
Earnings derived from:
Operations $.29 $.27 $1.00 $.99
Non-recurring events:
Sale of stock investment 3.38 - 3.38 -
Sale of subsidiary assets - - .04 -
Cumulative effect of change
in accounting - - - $.28
---------
- --------------------------------------------------------------------------------
Earnings per weighted average share $3.67 $.27 $4.42 $1.27
================================================================================
Earnings per share from operations for the three months ended June 30,
2001 increased $.02 as compared to 2000. The Company experienced an increase in
gas margin of $.02, improvements in the results of Energy Marketing of $.07 and
other improvements of $.01. These improvements were partially offset by a
decline in electric margin ($.02), and increases in operation and maintenance
expense ($.02), interest expense ($.02) and depreciation expense ($.02).
Earnings per share from operations for the six months ended June 30,
2001 increased $.01 as compared to 2000. The Company experienced improved
electric and gas margins of $.02 and $.11, respectively, improvements in the
results of Energy Marketing of $.07, and other improvements of $.04. These
improvements were partially offset by increased operation and maintenance
expense ($.14), interest expense ($.07) and depreciation expense ($.02) .
For the last several years, the market value of the Company's retirement
plan assets has exceeded the total actuarial present value of accumulated plan
benefits. Pension income for the three and six months ended June 30, 2001 was
$10.1 million and $20.2 million, respectively, compared to $9.8 million and
$19.6 million for the corresponding periods in 2000. As a result of pension
income, employee benefit expenses were reduced approximately $5.3 million and
$10.6 million for the three and six months ended June 30, 2001, compared to $5.0
million and $10.1 million for the corresponding periods in 2000. In addition,
other income increased $2.9 million and $5.9 million for the three and six
months ended June 30, 2001, respectively, compared to $3.0 million and $6.0
million for the corresponding periods in 2000.
The Company recognized a non-recurring gain of $3.38 per share in
connection with the sale of its investment in Powertel, Inc., which was acquired
by Deutsche Telekom AG in May 2001 (see Note 8 of Notes to Condensed
Consolidated Financial Statements). The Company also recognized a gain of $.04
per share in connection with the sale of the assets of SCANA Security in March
2001. In 2000, earnings from the cumulative effect of change in accounting
resulted from the recording of unbilled revenues by SCANA's regulated retail
utility subsidiaries (see Note 2 of Notes to Condensed Consolidated Financial
Statements).
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 less than one percent and
approximately three percent of income before taxes for the three months ended
June 30, 2001 and 2000, respectively. AFC represented approximately one percent
and two percent of income before income taxes for the six months ended June 30,
2001 and 2000, respectively.
The Company's Board of Directors declared the following quarterly
dividends on common stock during 2001:
- --------------------- --------------- --------------------- -------------------
Declaration Dividend Record Payment
Date Per Share Date Date
- --------------------- --------------- --------------------- -------------------
February 22, 2001 $.30 March 9, 2001 April 1, 2001
- ---------------------
May 3, 2001 $.30 June 8, 2001 July 1, 2001
- ---------------------
August 2, 2001 $.30 September 10, 2001 October 1, 2001
- --------------------- --------------- --------------------- -------------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G, South
Carolina Generating Company (GENCO) and South Carolina Fuel Company (Fuel
Company). Changes in the electric operations sales margins, including
transactions with affiliates and excluding the cumulative effect of accounting
change, for the three and six months ended June 30, 2001, when compared to the
corresponding periods in 2000, were as follows:
- ---------------------------------------- --------- --------- -------- --------- --------- ---------- ----------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- --------------------------------------- ---------- ------------------ --------- --------- ---------------------
Electric operating revenue $340.5 $319.8 $20.7 6.5% $680.7 $614.1 $66.6 10.8%
Less: Fuel used in generation 67.9 72.7 (4.8) (6.6%) 135.1 142.8 (7.7) (5.4%)
Purchased power 39.0 10.7 28.3 * 87.5 17.4 70.1 *
- ---------------------------------------- --------- --------- --------- --------- ----------
Margin $233.6 $236.4 $(2.8) (1.2%) $458.1 $453.9 $4.2 0.9%
======================================== ========= ========= ======== ========= ========= ========== ==========
*Greater than 100%
Changes in electric operations sales margins for the three months ended
June 30, 2001 reflect milder weather and an economic slowdown. Changes in
electric operations sales margins for the six months ended June 30, 2001 reflect
steady customer growth partially offset by weather and an economic slowdown.
Increases in purchased power costs for both periods, as compared to the
corresponding periods in 2000, were primarily attributable to plant outages
discussed at Liquidity and Capital Resources, which delayed scheduled
maintenance outages at other plants until April and May 2001.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC. Changes in the gas distribution sales margins, including
transactions with affiliates and excluding the cumulative effect of accounting
change, for the three and six months ended June 30, 2001, when compared to the
corresponding periods in 2000, were as follows:
- ------------------------------------------- --------- ---------- --------- --------- --------- ---------- -----------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- -------------------------------------------- --------- ------------------- --------- --------- ----------------------
Gas distribution operating revenue $125.0 $106.3 $18.7 17.6% $510.5 $361.9 $148.6 41.1%
Less: Gas purchased for resale 88.1 21.9 33.1% 367.7 218.9 148.8 68.0%
66.2
- -------------------------------------------- -------- ---------- --------- --------- -----------
Margin $36.9 $40.1 $(3.2) (8.0%) $142.8 $143.0 $(0.2) (0.1%)
============================================ ======== ========== ========= ========= ========= =========== ==========
Changes in gas distribution sales margins for the three and six months
ended June 30, 2001 reflect milder weather and an economic slowdown. For the six
months ended June 30, 2001, these factors were partially offset by customer
growth. Revenues and purchases were impacted by large increases in natural gas
prices in late 2000 and early 2001.
Gas Transmission
Gas Transmission is comprised of the operations of South Carolina
Pipeline Corporation. Changes in the gas transmission sales margins, including
transactions with affiliates, for the three and six months ended June 30, 2001,
when compared to the corresponding periods in 2000, were as follows:
- ------------------------------------------- --------- -------- ----------- --------- ---------- --------- -----------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- ------------------------------------------- ---------- ------------------- --------- --------- ----------------------
Gas transmission operating revenue $97.1 $98.7 $(1.6) (1.6%) $298.4 $215.7 $82.7 38.3%
Less: Gas purchased for resale 86.5 84.5 2.0 2.4% 278.7 186.6 92.1 49.4%
- ------------------------------------------- --------- -------- --------- ---------- ---------
Margin $10.6 $14.2 $(3.6) (25.4%) $19.7 $29.1 $(9.4) (32.3%)
=========================================== ========= ======== =========== ========= ========== ========= ===========
Gas transmission sales margins for the three and six months ended June
30, 2001 decreased primarily as a result of an economic slowdown and reduced
industrial margins due to the unfavorable competitive position of natural gas
relative to alternate fuels. Revenues and purchases were impacted by large
increases in natural gas prices in late 2000 and early 2001.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in Georgia's deregulated natural gas
market. Retail gas marketing revenues and net income for the three and six
months ended June 30, 2001, when compared to the corresponding periods in 2000,
were as follows:
- ---------------------------------- --------- --------- ----------- -------- --------- ---------- -----------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- ------------------------------------ ------- --------------------- -------- --------- ----------------------
Operating revenues $121.0 $91.6 $29.4 32.1% $384.0 $226.9 $157.1 69.2%
Net income(loss) $(0.2) (8.7%) $6.8 $6.6 $0.2 3.0%
$(2.5) $(2.3)
==================================== ======== ========= ========== ========= ========= ========== ==========
Operating revenues for the three and six months ended June 30, 2001
increased primarily as a result of record high natural gas prices. Although
operating revenues increased, net loss for the three months ended June 30, 2001
increased as a result of higher 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 for the three
and six months ended June 30, 2001, when compared to the corresponding periods
in 2000, were as follows:
- ---------------------------------- --------- --------- ---------- --------- --------- ---------- ---------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- --------------------------------- ---------- -------------------- --------- --------- --------------------
Operating revenues $103.9 $86.2 $17.7 20.5% $351.6 $169.7 $181.9 *
Net income(loss) $1.6 $0.8 $0.8 100% $5.1 $6.6 *
$(1.5)
================================== ========= ========= ========== ========= ========== ========= =========
*Greater than 100%
Operating revenues for the three and six months ended June 30, 2001
increased primarily as a result of record high natural gas prices. More
favorable weather in early 2001 also contributed to the increase in operating
revenues for the six months ended June 30, 2001. Net income improved primarily
due to the favorable changes in market value of certain transportation contracts
resulting from volatility in the natural gas market in early 2001.
Other Operating Expenses
Changes in other operating expenses for the three and six months ended
June 30, 2001, when compared to the corresponding periods in 2000, were as
follows:
- ---------------------------------------- ---------- --------- ---------- ---------- --------- ---------- ---------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- -------------------------------------------- ------------- ------------- ------------- ------------- -------------
Other operation and maintenance $122.0 $119.6 $2.4 2.0% $251.3 $228.6 $22.7 9.9%
Depreciation and amortization 56.2 52.8 3.4 6.4% 111.8 107.6 4.2 3.9%
Other taxes 28.8 28.9 (0.1) (0.3%) 58.7 0.5 0.9%
58.2
- ---------------------------------------- ---------- --------- ---------- --------- ----------
Total $207.0 $201.3 $5.7 2.8% $421.8 $394.4 $27.4 6.9%
======================================== ========== ========= ========== ========== ========= ========== =========
Other operation and maintenance expenses increased primarily as a result
of increased revenue-related expenses (e.g. provision for bad debts) for energy
sales and increased employee benefit costs. Depreciation and amortization
increased due to normal property additions. Other taxes for the six months ended
June 30, 2001 increased primarily due to increased property taxes.
Other Income
Other income for the three and six months ended June 30, 2001 increased
when compared to the corresponding periods in 2000, primarily due to the non-
recurring gain recognized in May 2001 in connection with the Company's
investment in Powertel, Inc., which was acquired by Deutsche Telekom AG, and the
March 2001 gain on the sale of the assets of SCANA Security (see Note 8 of Notes
to Condensed Consolidated Financial Statements).
Interest Expense
Interest expense for the three and six months ended June 30, 2001
increased when compared to the corresponding periods in 2000, primarily due to
the issuance of debt in mid-2000 and early 2001. The proceeds of such debt
offerings were used to refinance debt related to the acquisition of PSNC in
February 2000 and for general corporate purposes, including providing working
capital for natural gas purchases.
Income Taxes
Income taxes for the three and six months ended June 30, 2001 increased
approximately $190.0 million when compared to the corresponding periods in 2000.
This change is primarily due to the non-recurring gain recorded in May 2001 in
connection with the sale of the Company's investment in Powertel, Inc., which
was acquired by Deutsche Telekom AG (see Note 8 of Notes to Condensed
Consolidated Financial Statements).
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
June 30, 2001 Expected Maturity Date
Millions of dollars
There- Fair
Liabilities 2001 2002 2003 2004 2005 after Total Value
- ------------------------------------- -------- --------- ---------- ---------- ---------- ---------- ------------ ---------
- ------------------------------------- -------- --------- ---------- ---------- ---------- ---------- ------------ ---------
Long-Term Debt:
Fixed Rate ($) 35.8 37.7 297.6 186.4 182.0 1,746.3 2,485.8 2,528.1
Average Fixed Interest Rate 7.25 7.21 6.38 7.58 7.43 7.16 7.12
Variable Rate ($) 700.0 202.0 902.0 901.9
Average Variable Interest Rate 5.05 5.52 5.16
Interest Rate Swap:
Pay Variable/Receive Fixed ($) 300 300
0.3
Average Pay Interest Rate 4.68 4.68
Average Receive Interest Rate 6.88 6.88
While a decrease in interest rates would increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.
In addition, the Company has an investment in the 11.875 percent senior
discount notes (due 2007) of a telecommunications company, the cost basis of
which is approximately $61.3 million . The fair value of these notes
approximates cost. An increase in market interest rates would result in a
decrease in fair value of these notes and a corresponding adjustment, net of tax
effect, to other comprehensive income.
Commodity price risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.
As of June 30, 2001 Expected Maturity in 2001 Expected Maturity in 2002 Expected Maturity in 2003
------------------------- ------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Millions of dollars Settlement Contract Fair Settlement Contract Fair Settlement Contract Fair
Natural Gas Derivatives: Price Amount Value Price Amount Value Price Amount Value
- --------------------------- ----------- ---------- ------------ ---------- ------- ------------ ---------- -------
--------
Futures Contracts:
Long($) 3.4 98.7 72.8 3.6 118.3 96.0 3.8 2.2 2.1
Short($) 3.4 1.5 1.1 3.5 1.1 0.9 - - -
SET Futures Contracts1:
Short($) 3.2 0.9 0.7 - - - - - -
- --------------------------- ----------- ---------- -------- ------------ ---------- ------- ------------ ---------- -------
Expected Maturity in 2001
Natural Gas Derivatives: Weighted Average Strike Price Contract Amount
------------------------------------------------------------------------------
------------------------------------------------------------------------------
(Millions of dollars)
Options:
Purchased call (long)($) 5.699 9.2
------------------------------------------------------------------------------
Expected Maturity in 2001
Weighted Average Weighted Average Notional Amounts
Natural Gas Derivatives: Pay Rate Receive Rate (10,000 mmbtu)
------------------------------------------------------------------------------
Swaps:
SET1 $4.9181 $5.0637 766
------------------------------------------------------------------------------
------------------------------------------------------------------------------
1 SCANA Energy Trading, LLC (SET) is a 70 percent owned subsidiary of SCANA
Energy Marketing, Inc. Amounts shown are at 100 percent.
See Note 7 of Notes to Condensed Consolidated Financial Statements for
additional information.
Equity price risk - Certain investments in telecommunications companies'
marketable equity securities are carried at their market value of approximately
$965.4 million. A ten percent decline in market value would result in a $96.5
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.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------
June 30, December 31,
Millions of dollars 2001 2000
- --------------------------------------------------------------------------------
Assets
Utility Plant:
Electric $4,450 $4,453
Gas 411 409
Other 188 186
- --------------------------------------------------------------------------------
Total 5,049 5,048
Less accumulated depreciation and amortization 1,785 1,720
- --------------------------------------------------------------------------------
Total 3,264 3,328
Construction work in progress 374 230
Nuclear fuel, net of accumulated amortization 51 57
- --------------------------------------------------------------------------------
Utility Plant, Net 3,689 3,615
- --------------------------------------------------------------------------------
Nonutility Property and Investments, Net 22 21
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments 30 60
Receivables 256 287
Inventories (at average cost):
Fuel 33 21
Materials and supplies 46 46
Emission allowances 17 20
Prepayments 17 5
- --------------------------------------------------------------------------------
Total Current Assets 399 439
- --------------------------------------------------------------------------------
Deferred Debits:
Environmental 27 20
Nuclear plant decommissioning fund 75 72
Pension asset, net 216 196
Other regulatory assets 205 191
Other 128 110
- --------------------------------------------------------------------------------
Total Deferred Debits 651 589
- --------------------------------------------------------------------------------
Total $4,761 $4,664
================================================================================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- --------------------------------------------------------------------------------------- -------------------- -------------------
June 30, December 31,
Millions of dollars 2001 2000
- --------------------------------------------------------------------------------------- -------------------- -------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $1,688 $1,657
Preferred stock (Not subject to purchase or sinking funds) 106 106
- --------------------------------------------------------------------------------------- -------------------- -------------------
Total Stockholders' Investment 1,794 1,763
Preferred Stock, net (Subject to purchase or sinking funds) 10 10
Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's
Subsidiary Trust, SCE&G Trust I, Holding solely $50 million principal amount
of the 7.55%
Junior Subordinated Debentures of SCE&G, due 2027 50 50
Long-Term Debt, net 1,415 1,267
- --------------------------------------------------------------------------------------- -------------------- -------------------
Total Capitalization 3,269 3,090
- --------------------------------------------------------------------------------------- -------------------- -------------------
Current Liabilities:
Short-term borrowings 116 188
Current portion of long-term debt 28 28
Accounts payable 87 103
Accounts payable - affiliated companies 23 58
Customer deposits 18 17
Taxes accrued 37 51
Interest accrued 28 22
Dividends declared 44 44
Deferred income taxes, net 24 20
Other 9 10
- --------------------------------------------------------------------------------------- -------------------- -------------------
Total Current Liabilities 414 541
- --------------------------------------------------------------------------------------- -------------------- -------------------
Deferred Credits:
Deferred income taxes, net 603 584
Deferred investment tax credits 107 109
Reserve for nuclear plant decommissioning 75 72
Postretirement benefits 117 113
Regulatory liabilities 79 65
Other 97 90
- --------------------------------------------------------------------------------------- -------------------- -------------------
Total Deferred Credits 1,078 1,033
- --------------------------------------------------------------------------------------- -------------------- -------------------
Total $4,761 $4,664
======================================================================================= ==================== ===================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Unaudited)
- ------------------------------------------------------------------------- ------------------------------ --------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2001 2000 2001 2000
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Operating Revenues:
Electric $342 $320 $683 $614
Gas 58 51 215 151
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Total Operating Revenues 400 371 898 765
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Operating Expenses:
Fuel used in electric generation 55 55 105 112
Purchased power (including affiliated purchases) 61 37 136 67
Gas purchased for resale 46 39 165 100
Other operation and maintenance 84 81 162 154
Depreciation and amortization 41 39 82 79
Other taxes 25 24 50 50
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Total Operating Expenses 312 275 700 562
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Operating Income 88 96 198 203
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Other Income:
Other Income, including allowance for equity funds
used during construction 9 2 13 7
Gain on sale of assets 1 - 1 1
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Total Other Income 10 2 14 8
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Income Before Interest Charges, Income Taxes, Preferred Stock
Dividends and Cumulative Effect of Accounting Change 98 98 212 211
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Interest Charges:
Interest expense on long-term debt, net 28 25 56 49
Other interest expense, net of allowance for borrowed
funds used during construction - 1 3
-
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Total Interest Charges, Net 28 26 56 52
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 70 72 156 159
Income Taxes 26 27 57 58
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Income Before Preferred Stock Dividends
and Cumulative Effect of Accounting Change 44 45 99 101
Preferred Dividend Requirement of the Company - Obligated
Mandatorily Redeemable Preferred Securities 1 1 2 2
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Income Before Cumulative Effect of Accounting Change 43 44 97 99
Cumulative Effect of Accounting Change, net of taxes (Note 2) - - - 22
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Net Income 43 44 97 121
Preferred Stock Cash Dividends Declared (At stated rates) (2) (2) (4)
(4)
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Earnings Available for Common Stockholder 41 42 93 117
Retained Earnings at Beginning of Period 666 593 649 550
Common Stock Cash Dividends Declared (42) (32) (64)
(77)
- ------------------------------------------------------------------------- --------------- -------------- -------- -----------------
Retained Earnings at End of Period $665 $603 $665 $603
========================================================================= =============== ============== ======== =================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -------------------------------------------------------------------------------------------- ----------------------------
Six Months Ended
June 30,
Millions of dollars 2001 2000
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash Flows From Operating Activities:
Net income $97 $121
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes - (22)
Depreciation and amortization 82 79
Amortization of nuclear fuel 6 10
Gain on sale of assets (1) (1)
Allowance for funds used during construction (7) (3)
Over (under) collections, fuel adjustment clauses (11) 11
Changes in certain assets and liabilities:
(Increase) decrease in receivables 31 (18)
(Increase) decrease in inventories (9) 5
(Increase) decrease pension asset (20) (19)
(Increase) decrease other regulatory assets 2 8
Increase (decrease) deferred income taxes, net 19 14
Increase (decrease) other regulatory liabilities 9 3
Increase (decrease) postretirement benefits 4 4
Increase (decrease) in accounts payable (51) (10)
Increase (decrease) in taxes accrued (14) 9
Other, net (26) (18)
- -------------------------------------------------------------------------------------------- -------------- -------------
Net Cash Provided From Operating Activities 111 173
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (150) (113)
Nonutility property additions (1) -
Proceeds from sale of assets 1 1
Investments -
(4)
- -------------------------------------------------------------------------------------------- -------------- -------------
- -------------------------------------------------------------------------------------------- -------------- -------------
Net Cash Used For Investing Activities (150) (116)
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 149 148
Capital contribution from Parent 15 -
Repayments:
First Mortgage Bonds - (100)
Other long-term debt (2)
(2)
Dividend payments:
Common stock (77) (57)
Preferred stock (4) (4)
Short-term borrowings, net (72) (77)
- -------------------------------------------------------------------------------------------- -------------- -------------
Net Cash Provided From (Used For) Financing Activities 9 (92)
- -------------------------------------------------------------------------------------------- -------------- -------------
Net Decrease In Cash and Temporary Investments (30) (35)
Cash and Temporary Investments, January 1 60 78
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash and Temporary Investments, June 30 $30 $43
============================================================================================ ============== =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $4 for 2001 and $2 for 2000) $77 $50
- Income taxes 11 17
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2001
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in South Carolina Electric & Gas
Company's (the Company) Annual Report on Form 10-K for the year ended December
31, 2000. These are interim financial statements, and due to the seasonality of
the Company's business, the amounts reported in the Condensed Consolidated
Statements of Income are not necessarily indicative of amounts expected for the
year. In the opinion of management, the information furnished herein reflects
all adjustments, all of a normal recurring nature except as described in Notes 2
and 3, which are necessary for a fair statement of the results for the interim
periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This accounting standard requires
cost-based rate-regulated utilities to recognize in their financial
statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result, the Company has
recorded, as of June 30, 2001, approximately $232 million and $79 million
of regulatory assets and liabilities, respectively, including amounts
recorded for deferred income tax assets and liabilities of approximately
$129 million and $60 million, respectively. The electric and gas
regulatory assets of approximately $72 million and $30 million,
respectively, (excluding deferred income tax assets) are recoverable
through rates. In the future, as a result of deregulation or other
changes in the regulatory environment, the Company may no longer meet the
criteria for continued application of SFAS 71 and could be required to
write off its regulatory assets and liabilities. Such an event could have
a material adverse effect on the Company's results of operations in the
period the write-off would be recorded, but it is not expected that cash
flows or financial position would be materially affected.
B. New Accounting Standards
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. The Company's
adoption of SFAS 133, as amended, did not have a material impact on the
Company's results of operations, cash flows or financial position.
In June 2001 the Financial Accounting Standards Board approved the
issuance of three new accounting standards. SFAS 141, "Business
Combinations," requires that all business combinations be accounted for
using the purchase method of accounting. SFAS 141 applies to all business
combinations initiated after June 30, 2001, and is not expected to have
any impact on the Company's results of operations, cash flows or
financial position.
SFAS 142, "Goodwill and Other Intangible Assets," requires that goodwill
not be amortized but instead be tested for impairment at least annually
at the reporting unit level. A reporting unit is the same level as, or
one level below, an operating segment. The Company will adopt SFAS 142
effective January 1, 2002. The impact SFAS 142 may have on the Company's
results of operations, cash flows or financial position has not been
determined.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will
adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on
the Company's results of operations, cash flows and financial position
has not been determined.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2001.
2. Cumulative Effect of Accounting Change
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues from cycle billing to full accrual. The
cumulative effect of this change was $22 million, net of tax. Accruing
unbilled revenues more closely matches revenues and expenses. Unbilled
revenues represent the estimated amount customers will be charged for
service rendered but not yet billed as of the end of the accounting
period.
3. RATE AND OTHER REGULATORY MATTERS
A. On April 24, 2001 the Public Service Commission of South Carolina
(PSC) approved the Company's request to increase the fuel component
of rates charged to electric customers from 1.330 cents per
kilowatt-hour to 1.579 cents per kilowatt-hour. The increase
reflects higher fuel costs projected for the period May 2001 through
April 2002. The increase also provides recovery over a twoyear
period of under-collected actual fuel costs through April 2001,
including short-term purchased power costs necessitated by outages
at two of the Company's base load generating plants in winter
2000-2001. The new rates were effective as of the first billing
cycle in May 2001.
B. On July 20, 2000 the PSC approved the Company's request for an
out-of-period adjustment to increase the cost of gas component of
its rates for natural gas service from 54.334 cents per therm to
68.835 cents per therm, effective with the first billing cycle in
August 2000. As part of its regularly scheduled annual review of gas
costs, the PSC issued an order on November 9, 2000 which further
increased the cost of gas component to 78.151 cents per therm,
effective with the first billing cycle in November 2000. On December
21, 2000 the PSC issued an order approving the Company's request for
another out-of-period adjustment to increase the cost of gas
component to 99.340 cents per therm, effective with the first
billing cycle in January 2001. On March 9, 2001 the PSC issued an
order granting the Company's request to reduce the cost of gas
component to 79.340 cents per therm, effective with the first
billing cycle in March 2001.
C. On July 5, 2000 the PSC approved the Company's request to implement
lower depreciation rates for its gas operations. The new rates were
effective retroactively to January 1, 2000 and resulted in a
reduction in annual depreciation expense of approximately $2.9
million. The retroactive effect was recorded in the second quarter
of 2000.
D. On September 14, 1999 the PSC approved an accelerated capital
recovery plan for the Company's Cope Generating Station. The plan
was implemented beginning January 1, 2000 for a three-year period.
The PSC approved an accelerated capital recovery methodology wherein
the Company may increase depreciation of its Cope Generating Station
in excess of amounts that would be recorded based upon currently
approved depreciation rates. The amount of the accelerated
depreciation will be determined by the Company based on the level of
revenues and operating expenses, not to exceed $36 million annually
without the approval of the PSC. Any unused portion of the $36
million in any given year may be carried forward for possible use in
the following year. As of June 30, 2001 no accelerated depreciation
has been recorded. The accelerated capital recovery plan will be
accomplished through existing customer rates.
E. On January 9, 1996 the PSC issued an order granting the Company an
increase in retail electric rates which was fully implemented by
January 1997. The PSC authorized a return on common equity of 12.0
percent. The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over a
ten-year period. Additionally the PSC approved accelerated
amortization of a significant portion of the Company's electric
regulatory assets (excluding deferred income tax assets) and the
remaining transition obligation for postretirement benefits other than
pensions, which enabled the Company to recover the balances as of the
end of the year 2000.
F. In 1994 the PSC issued an order approving the Company's request to recover
through a billing surcharge to its gas customers the costs of environmental
cleanup at the sites of former manufactured gas plants (MGPs). The billing
surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs
and environmental claims settlements for the Company's gas operations that
had previously been deferred. In November 2000, as a result of the annual
review, the PSC approved the Company's request to maintain the billing
surcharge of $.011 per therm that provides for the recovery of the balance
remaining at June 30, 2001 of $26.3 million.
4. LONG-TERM DEBT
On January 24, 2001 the Company issued $150 million First Mortgage Bonds
having an annual interest rate of 6.70 percent and maturing on February
1, 2011. The proceeds from the sale of these bonds were used to reduce
short-term debt and for general corporate purposes.
5. RETAINED EARNINGS
The Company's Restated Articles of Incorporation and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions
that, under certain circumstances, could limit the payment of cash
dividends on its common stock. In addition, with respect to
hydroelectric projects, the Federal Power Act requires the appropriation
of a portion of certain earnings therefrom. At June 30, 2001
approximately $34.8 million of retained earnings were restricted by this
requirement as to payment of cash dividends on common stock.
6. CONTINGENCIES
With respect to commitments at June 30, 2001, reference is made to Note
12 of Notes to Consolidated Financial Statements appearing in the
Company's Annual Report on Form 10-K for the year ended December 31,
2000. Contingencies at June 30, 2001 include the following:
A. Lake Murray Dam Reinforcement
On October 15, 1999 the Federal Energy Regulatory Commission (FERC)
notified the Company of its agreement with the Company's plan to
reinforce Lake Murray Dam in order to maintain the lake in case of an
extreme earthquake. The Company and FERC have been discussing possible
reinforcement alternatives for the dam over the past several years as
part of the Company's ongoing hydroelectric operating license with FERC.
The cost and completion date of this project will depend on the
reinforcement alternative ultimately approved by FERC; however, it is
possible that the costs could range up to $300 million with completion
dates ranging from 2004 to 2006. Although any costs incurred by the
Company are expected to be recoverable through electric rates, the
Company also is exploring alternative sources of funding.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public
liability for a nuclear incident, currently establishes the liability
limit for third-party claims associated with any nuclear incident at $9.5
billion. Each reactor licensee is currently liable for up to $88.1
million per reactor owned for each nuclear incident occurring at any
reactor in the United States, provided that not more than $10 million of
the liability per reactor would be assessed per year. The Company's
maximum assessment, based on its two-thirds ownership of the V. C. Summer
Nuclear Station (Summer Station), would be approximately $58.7 million
per incident, but not more than $6.7 million per year.
The Company currently maintains policies (for itself and on behalf of
the South Carolina Public Service Authority) with Nuclear Electric
Insurance Limited. The policies, covering the nuclear facility for
property damage, excess property damage and outage costs, permit
assessments under certain conditions to cover insurer's losses. Based on
the current annual premium, the Company's portion of the retrospective
premium assessment would not exceed $8.1 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and expenses
arising from a nuclear incident at Summer Station exceed the policy limits
of insurance, or to the extent such insurance becomes unavailable in the
future, and to the extent that the Company's rates would not recover the
cost of any purchased replacement power, the Company will retain the risk
of loss as a self-insurer. The Company has no reason to anticipate a
serious nuclear incident at Summer Station. If such an incident were to
occur, it could have a material adverse impact on the Company's results of
operations, cash flows and financial position.
C. Environmental
The Company maintains an environmental assessment program to identify and
assess 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
$26.3 million at June 30, 2001. The deferral includes the estimated costs
associated with the following matters.
o In September 1992 the Environmental Protection Agency (EPA) notified
the Company, the City of Charleston and the Charleston Housing
Authority of their potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina.
This site encompasses approximately 30 acres and includes properties
which were locations for industrial operations, including a wood
preserving (creosote) plant, one of the Company's decommissioned MGPs,
properties owned by the National Park Service and the City of
Charleston and private properties. The site has not been placed on the
National Priorities List, but may be added in the future. The
Potentially Responsible Parties (PRPs) negotiated an administrative
order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope of Work.
Field work began in November 1993, and the EPA approved a Remedial
Investigation Report in February 1997 and a Feasibility Study Report
in June 1998. In July 1998 the EPA approved the Company's Removal
Action Work Plan for soil excavation. The Company completed Phase One
of the Removal Action Work Plan in 1998 at a cost of approximately
$1.5 million. Phase Two, which cost approximately $3.5 million,
included excavation and installation of several permanent barriers to
mitigate coal tar seepage. In September 1998 a Record of Decision was
issued which sets forth the EPA's view of the extent of each PRP's
responsibility for site contamination and the level to which the site
must be remediated. The Company estimates that the Record of Decision
will result in costs of approximately $16.5 million, of which
approximately $1.6 million remains. In January 1999 the EPA issued a
Unilateral Administrative Order for Remedial Design and Remedial
Action directing the Company to design and carry out a plan of
remediation for the Calhoun Park site. The Company submitted a
Comprehensive Remedial Design Work Plan (RDWP) in December 1999 and
proceeded with implementation pending agency approval. The RDWP was
approved by the EPA in July 2000, and its implementation continues.
In September 2000, the Company was notified by the South Carolina
Department of Health and Environmental Control (DHEC) that benzene
contamination was detected in the intermediate aquifer on surrounding
properties to the Calhoun Park Area site. The EPA has required that
the Company conduct a focused Remedial Investigation/Feasibility Study
on the intermediate aquifer. The EPA expects to issue a second Record
of Decision dealing with the intermediate aquifer in September 2001.
Intermediate groundwater investigation and cleanup is expected to cost
approximately $4.7 million.
o The Company owns three other decommissioned MGP sites in South
Carolina which contain residues of by-product chemicals. For the site
located in Sumter, effective September 15, 1998, the Company entered
into a Remedial Action Plan Contract with DHEC pursuant to which it
agreed to undertake a full site investigation and remediation under
the oversight of DHEC. Site investigation, characterization and
remediation are proceeding according to schedule. Excavation at the
Sumter MGP site was completed in May 2001 as part of an Interim
Removal Action. Further work may be required at the discretion of
DHEC. Upon successful implementation of a site remedy, DHEC will give
the Company a Certificate of Completion and a covenant not to sue. For
the site located in Florence the Company entered into a similar
Remedial Action Plan Contract with DHEC in September 2000. The Company
is continuing to investigate the remaining site in Columbia, and is
monitoring the nature and extent of residual contamination.
7. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are listed in the following table. The Company
uses operating income to measure profitability for its reportable segments.
Therefore, net income is not allocated to these segments. Affiliate revenue is
derived from transactions between reportable segments as well as transactions
between separate legal entities that are combined into the same reportable
segment. Accumulated depreciation is not assignable to the Company's segments.
Disclosure of Reportable Segments
(Millions of Dollars)
- ------------------------------ ------------ ------------ ---------- ----------------- --------------
Three months ended Electric Gas All Adjustments/ Consolidated
June 30, 2001 Operations Distribution Other Eliminations Total
- ------------------------------ ------------ ------------ ---------- ----------------- --------------
External Revenue 342 58 - - 400
Intersegment Revenue 52 - - (52) -
Operating Income (Loss) 94 (5) - (1) 88
Segment Assets 4,790 423 199 (651) 4,761
- ------------------------------ ------------ ------------ ---------- ----------------- --------------
- ---------------------------- ------------ ------------ ---------- ----------------- --------------
Six months ended Electric Gas All Adjustments/ Consolidated
June 30, 2001 Operations Distribution Other Eliminations Total
- ---------------------------- ------------ ------------ ---------- ----------------- --------------
External Revenue 683 215 - - 898
Intersegment Revenue 99 - - (99) -
Operating Income (Loss) 184 16 - (2) 198
Segment Assets 4,790 423 199 (651) 4,761
- ---------------------------- ------------ ------------ ---------- ----------------- --------------
- ------------------------------ -------------- ------------ ------------------------- -------------
Three months ended Electric Gas All Adjustments/ Consolidated
June 30, 2000 Operations Distribution Other Eliminations Total
- ----------------------------- -------------- ------------ ------------------------- -------------
External Revenue 320 51 - - 371
Intersegment Revenue 51 - - (51) -
Operating Income (Loss) 99 (2) - (1) 96
Segment Assets 4,524 407 202 (677) 4,456
- ----------------------------- -------------- ------------ ------------------------- -------------
- ------------------------------- ------------ ------------ ------------------------- --------------
Six months ended Electric Gas All Adjustments/ Consolidated
June 30, 2000 Operations Distribution Other Eliminations Total
- ------------------------------- ------------ ------------ ------------------------- --------------
External Revenue 614 151 - - 765
Intersegment Revenue 106 - - (106) -
Operating Income (Loss) 85 21 - (3) 203
Segment Assets 4,524 407 202 (677) 4,456
- ------------------------------- ------------ ------------ ------------------------- --------------
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- -------------------------------------------------------------------------------
SOUTH CAROLINA ELECTRIC & GAS COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations
appearing in South Carolina Electric & Gas Company's (SCE&G) Annual Report on
Form 10-K for the year ended December 31, 2000.
Statements included in this discussion and analysis (or elsewhere in
this quarterly report) which are not statements of historical fact are intended
to be, and are hereby identified as, "forward looking statements" for purposes
of the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, (3) changes in the economy especially in SCE&G's service territory,
(4) the impact of competition from other energy suppliers, (5) growth
opportunities, (6) the results of financing efforts, (7) changes in SCE&G's
accounting policies, (8) weather conditions, especially in areas served by
SCE&G, (9) inflation, (10) changes in environmental regulations and (11) the
other risks and uncertainties described from time to time in SCE&G's periodic
reports filed with the Securities and Exchange Commission. SCE&G disclaims any
obligation to update any forward-looking statements.
LIQUIDITY AND CAPITAL RESOURCES
On October 15, 1999 the Federal Energy Regulatory Commission (FERC)
notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam
in order to maintain the lake in case of an extreme earthquake. SCE&G and FERC
have been discussing possible reinforcement alternatives for the dam over the
past several years as part of SCE&G's ongoing hydroelectric operating license
with FERC. The cost and completion date of this project will depend on the
reinforcement alternative ultimately approved by FERC; however, it is possible
that the costs could range up to $300 million with completion dates ranging from
2004 to 2006. Although any costs incurred by SCE&G are expected to be
recoverable through electric rates, SCE&G also is exploring alternative sources
of funding.
On February 9, 2000 FERC issued FERC Order 2000. The Order requires
utilities which operate electric transmission systems to submit plans for the
possible formation of a regional transmission organization (RTO). On October 16,
2000 SCE&G and two other southeastern electric utilities filed a joint request
with FERC to establish GridSouth Transco, LLC (GridSouth). FERC gave provisional
approval to GridSouth in March 2001. When operational, GridSouth will function
as an independent regional transmission company. In July 2001 FERC ordered
mediation talks to take place between the utilities forming GridSouth and
certain groups that have proposed other RTOs. These talks are being mediated by
an administrative law judge, with a stated goal of FERC being the formation of a
single RTO in the Southeast.
In March 2001 V. C. Summer Nuclear Station returned to service. It had
been taken out of service on October 7, 2000 for a planned maintenance and
refueling outage. During initial inspection activities, plant personnel
discovered a small leak coming from a hole in a weld in a primary coolant system
pipe. Repairs were completed and the integrity of the new welds was verified
through extensive testing. The PSC has approved recovery of the cost of
replacement power through SCE&G's electric fuel adjustment clause (see Note 3A
of Notes to Condensed Consolidated Financial Statements). The Nuclear Regulatory
Commission was closely involved throughout this process and approved SCE&G's
actions to repair the crack, as well as the restart schedule. SCE&G will
continue to monitor primary coolant system pipes during the next outage,
scheduled for Spring of 2002.
In April 2001 SCE&G announced plans to construct a 620 megawatt
combined cycle natural gas-fueled power plant in Jasper County, South Carolina,
to supply electricity to its South Carolina customers. The proposed generation
facility is estimated to cost between $250 million and $300 million.
Construction is expected to begin in the Summer of 2002 and is expected to be
completed in the Summer of 2004.
In April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
returned to service. It had been taken out of service in January 2001 due to an
electrical ground in the generator. The PSC has approved recovery of the cost of
replacement power through SCE&G's electric fuel adjustment clause (see Note 3A
of Notes to Condensed Consolidated Financial Statements).
The following table summarizes how SCE&G generated and used funds for
property additions and construction expenditures during the six months ended
June 30, 2001 and 2000:
- -------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2001 2000
- -------------------------------------------------------------------- ----------
Net cash provided from operating activities $111 $173
Net cash provided from (used for) financing activities 9 (92)
Cash and temporary cash investments available
at the beginning of the period 60 78
- ----------------------------------------------------------------- -------------
Net cash available for utility property
additions and construction expenditures $180 $159
================================================================= =============
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $150 $113
Funds used for investments - $4
================================================================= =============
On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds
having an annual interest rate of 6.70 percent and maturing on February 1, 2011.
The proceeds were used to reduce short-term debt and for general corporate
purposes.
SCE&G anticipates that the remainder of its 2001 cash requirements will
be met through internally generated funds and the incurrence of additional
short-term and long-term indebtedness. SCE&G expects that it has or can obtain
adequate sources of financing to meet its projected cash requirements for the
next 12 months and for the foreseeable future. SCE&G's ratio of earnings to
fixed charges for the 12 months ended June 30, 2001 was 4.01.
Environmental Matters
For information on environmental matters see Note 6C "Contingencies -
Environmental" of Notes To Condensed Consolidated Financial Statements appearing
in this Quarterly Report on Form 10-Q.
RESULTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2001
AS COMPARED TO THE CORRESPONDING PERIODS IN 2000
Earnings and Dividends
Changes in net income for the three and six months ended June 30, 2001
and 2000 were as follows:
-----------------------------------------------------------------------------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 2001 2000
------------------------------------------- ---------------------------------
Net income derived from:
Operations $43.0 $44.3 $96.5 $98.5
Cumulative effect of
change in accounting - - - 22.3
------------------------------------------- ---------------------------------
Total net income $43.0 $44.3 $96.5 $120.8
=========================================== =================================
Net income from operations for the three months ended June 30, 2001
decreased primarily due to milder weather and increases in interest expense and
other operation and maintenance expense, which were partially offset by customer
growth.
Net income from operations for the six months ended June 30, 2001
decreased primarily due to milder weather, increases in interest expense and
other operation and maintenance expense and an economic slowdown, which were
partially offset by customer growth.
For the last several years, the market value of the Company's retirement
plan assets has exceeded the total actuarial present value of accumulated plan
benefits. Pension income for the three and six months ended June 30, 2001 and
2000 was $7.8 million and $15.6 million, respectively. As a result of pension
income, employee benefit expenses were reduced approximately $4.8 million and
$9.6 million for the three and six months ended June 30, 2001. For the
corresponding periods in 2000, employee benefit costs were reduced approximately
$4.7 million and $9.5 million. Additionally, other income increased $3.0 million
and $6.0 million for the three and six months ended June 30, 2001 and 2000.
Earnings from the cumulative effect of change in accounting resulted
from recording of unbilled revenue (See Note 2 of Notes to Condensed
Consolidated Financial Statements).
Allowance for funds used during construction (AFC) is a utility
accounting practice whereby a portion of the cost of both equity and borrowed
funds used to finance construction (which is shown on the balance sheet as
construction work in progress) is capitalized. Both the equity and the debt
portions of AFC are noncash items of nonoperating income which have the effect
of increasing reported net income. AFC represented approximately six percent and
five percent of income before income taxes for the three and six months ended
June 30, 2001, respectively. For the three and six months ended June 30, 2000,
AFC represented approximately two percent of income before income taxes.
SCE&G's Board of Directors declared the following quarterly dividends
on common stock held by SCANA, during 2001:
- ------------------- ----------------- ----------------------- ------------------
Declaration Dividend Quarter Payment
Date Amount Ended Date
- ------------------- ----------------- ----------------------- ------------------
February 22, 2001 $35.0 million March 31, 2001 April 1, 2001
- -------------------
May 3, 2001 $41.75 million June 30, 2001 July 1, 2001
- -------------------
August 2, 2001 $38.5 million September 30, 2001 October 1, 2001
- ------------------- ----------------- ----------------------- ------------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and
South Carolina Fuel Company. Changes in the electric operations sales margins,
excluding the cumulative effect of accounting change, for the three and six
months ended June 30, 2001, when compared to the corresponding periods in 2000,
were as follows:
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- -------------------------------------- --------- -------------------------------- ----------- ----------------------
Electric operating revenue $341.8 $319.8 $22.0 6.9% $683.4 $614.1 $69.3 11.3%
Less: Fuel used in generation 54.7 55.2 (0.5) (0.9%) 104.7 112.2 (7.5) (6.7%)
Purchased power 61.3 37.6 23.7 63.0% 135.9 66.6 69.3 *
- ------------------------------- ------- --------- ---------- --------- ----------- ------------------ ---------
Margin $225.8 $227.0 $(1.2) (0.5%) $442.8 $435.3 $7.5 1.7%
====================================== ========= ========== ===================== =========== =========== ==========
*Greater than 100%
Changes in electric operations sales margins for the three months ended
June 30, 2001 reflect milder weather and an economic slowdown. Changes in
electric operations sales margin for the six months ended June 30, 2001 reflect
steady customer growth partially offset by weather and an economic slowdown.
Increases in purchased power costs for both periods, as compared to the
corresponding periods in 2000, were primarily attributable to plant outages
discussed at Liquidity and Capital Resources, which delayed scheduled
maintenance outages at other plants until April and May 2001.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Changes in the gas distribution sales margins, excluding the cumulative
effect of accounting change, for the three and six months ended June 30, 2001,
when compared to the corresponding periods in 2000, were as follows:
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- ----------------------------------------- --------- ------------------------------ ---------- ----------------------
Gas operating revenue $57.8 $51.0 $6.8 13.3% $214.9 $151.5 $63.4 41.8%
Less: Gas purchased for resale 46.5 38.6 7.9 20.5% 165.4 100.3 65.1 64.9%
- ---------------------------------- ---------- ---------- ---------- -----------
------- ---------
Margin $11.3 $12.4 $(1.1) (8.9%) $49.5 $51.2 $(1.7) (3.3%)
========================================= ========= ========== =================== ========== =========== ==========
Gas distribution sales margins for the three and six months ended June
30, 2001 decreased as a result of milder weather and an economic slowdown.
Revenues and purchases were impacted by large increases in natural gas prices in
late 2000 and early 2001. The increased cost of gas was passed on to customers
as discussed in Note 3B in Notes To Condensed Consolidated Financial Statements.
Other Operating Expenses
Changes in other operating expenses for the three and six months ended
June 30, 2001 when compared to the corresponding periods in 2000, were as
follows:
- -------------------------------------- --------------------------------------- --------------------------------------------
Three Months Ended Six Months Ended
Millions of dollars 2001 2000 Change 2001 2000 Change
- -------------------------------------- --------- -------- -------------------- ---------- ---------- ----------------------
Other operation and maintenance $83.7 $80.8 $2.9 3.6% $162.6 $154.2 $8.4 5.4%
Depreciation and amortization 41.0 38.9 2.1 5.4% 81.6 79.2 2.4 3.0%
Other taxes 24.8 24.4 0.4 1.6% 50.4 49.6 0.8 1.6%
- -------------------------------------- --------- ---------- ---------- -------------
--------- --------
Total $149.5 $144.1 $5.4 3.7% $294.6 $283.0 $11.6 4.1%
====================================== ========= ======== ========= ========== ========== ========== ============= ========
Other operation expenses for the three and six months ended June 30, 2001
increased primarily as a result of increases in employee benefit costs. The
increase in depreciation and amortization expenses for the three and six months
ended June 30, 2001 resulted from normal property additions. Other taxes
increased primarily due to increased property taxes.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates.
June 30, 2001
Millions of dollars Expected Maturity Date
There- Fair
Liabilities 2001 2002 2003 2004 2005 after Total Value
- -------------------------------- -------- ------- --------- ----------------------------------------
- -------------------------------- -------- ------- --------- ----------------------------------------
Long-Term Debt:
Fixed Rate ($) 25.8 27.6 129.5 123.9 173.9 962.3 1,443.0 1,479.8
Average Interest Rate 6.74 6.72 6.37 7.52 7.40 7.43 7.32
While a decrease in interest rates would increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
--------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ----------------------------------------------------------------------------- ---------------------- --------------------------
June 30, December 31,
Millions of dollars 2001 2000
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Assets
Gas Utility Plant $811 $787
Less accumulated depreciation 275 263
Acquisition adjustment, net of accumulated amortization 446 452
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Gas Utility Plant, Net 982 976
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Nonutility Property and Investments, Net 29 34
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Current Assets:
Cash and temporary investments 39 8
Restricted cash and temporary investments 1 5
Receivables (net of allowance for uncollectible accounts of $1
for 2001 and $2 for 2000) 50 148
Inventories (at average cost):
Stored gas 37 32
Materials and supplies 8 7
Other 1 2
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total Current Assets 136 202
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Deferred Charges and Other Assets:
Due from affiliate-pension asset 10 10
Regulatory assets 17 21
Other 8 10
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total Deferred Charges and Other Assets 35 41
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total $1,182 $1,253
============================================================================= ====================== ==========================
============================================================================= ====================== ==========================
Capitalization and Liabilities
Capitalization:
Common equity $718 $712
Long-term debt, net 295 145
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total Capitalization 1,013 857
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Current Liabilities:
Short-term borrowings - 125
Current portion of long-term debt 4 4
Accounts payable 24 84
Taxes accrued - 3
Customer prepayments and deposits 4 8
Advances from parent - 44
Dividends declared and interest accrued 11 5
Other 2 1
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total Current Liabilities 45 274
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Deferred Credits and Other Liabilities:
Deferred income taxes, net 84 82
Due to affiliate-postretirement benefits 10 10
Regulatory liabilities 10 5
Other 20 25
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total Deferred Credits and Other Liabilities 124 122
- ----------------------------------------------------------------------------- ---------------------- --------------------------
Total $1,182 $1,253
============================================================================= ====================== ==========================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME(LOSS)
AND RETAINED EARNINGS
(Unaudited)
--------------------------------------------------------------------- ---------------------------- ------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2001 2000 2001 2000
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Operating Revenues $67 $80 $295 $250
Cost of Gas 41 52 202 156
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Gross Margin 26 28 93 94
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Operating Expenses:
Operation and maintenance 15 19 32 35
Depreciation and amortization 11 10 21 21
Other taxes 2 1 3 3
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Total Operating Expenses 28 30 56 59
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Operating Income(Loss) (2) (2) 37 35
Other Income, net 2 2 4 3
Interest Charges 5 5 11 10
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Income (Loss) Before Income Taxes and
Cumulative Effect of Accounting Change (5) (5) 30 28
Income Taxes - - 14 14
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Income(Loss) Before Cumulative Effect of Accounting Change (5) (5) 16 14
Cumulative Effect of Accounting Change, net of taxes (Note 2) - - - 7
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Net Income(Loss) (5) (5) 16 21
Retained Earnings at Beginning of Period 23 20 9 73
Acquisition of Company - - - (73)
Common Stock Cash Dividends Declared (5) (5) (12) (11)
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
--------------------------------------------------------------------- ------------- -------------- --------------- --------------
Retained Earnings at End of Period $13 $10 $13 $10
===================================================================== ============= ============== =============== ==============
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- ------------------------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2001 2000
- ----------------------------------------------------------------------------------- ------------
Cash Flows From Operating Activities:
Net income $16 $21
Adjustments to reconcile net income to net cash provided
from operating activities:
Cumulative effect of accounting change, net of taxes - (7)
Depreciation and amortization 24 23
Excess distributions (undistributed earnings) of investee 3 (3)
Over (under) collection, fuel adjustment clause 14 11
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 88 38
(Increase) decrease in inventories (6) 3
Increase (decrease) in accounts payable and advances (94) (11)
Increase (decrease) in deferred income taxes, net 2 2
Increase (decrease) in accrued taxes (2) (2)
Other, net (2) (8)
- ----------------------------------------------------------------------------------- ------------
Net Cash Provided From Operating Activities 43 67
- ----------------------------------------------------------------------------------- ------------
Cash Flows From Investing Activities:
Construction expenditures (29) (15)
Investments - (1)
Nonutility and other 1 -
- ----------------------------------------------------------------------------------- ------------
Net Cash Used For Investing Activities (28) (16)
- ----------------------------------------------------------------------------------- ------------
Cash Flows From Financing Activities:
Issuance of medium-term notes 148 -
Repayment of short-term borrowings, net (125) (38)
Retirement of long-term debt and common stock - (1)
Capital contribution from parent 3 -
Cash dividends (10) (11)
- ----------------------------------------------------------------------------------- ------------
Net Cash Provided From (Used For) Financing Activities 16 (50)
- ----------------------------------------------------------------------------------- ------------
Net Increase In Cash and Temporary Investments 31 1
Cash and Temporary Investments, January 1 8 9
- ----------------------------------------------------------------------------------- ------------
Cash and Temporary Investments, June 30 $39 $10
=================================================================================== ============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $0.6 for 2001
and $0.5 for 2000) $6 $11
- Income taxes 15 16
In connection with the acquisition of Public Service Company of North Carolina,
Inc. by SCANA Corporation, $21 million in common stock was cancelled. The
application of push-down accounting for the acquisition resulted in a $466
million acquisition adjustment.
Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service
Company LLC were sold to SCANA Energy Marketing, Inc., an affiliate, for $4.4
million, which approximated net book value. Assets transferred included
approximately $4.0 million cash.
See Notes to Condensed Consolidated Financial Statements.
60
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2001
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in Public Service Company of North
Carolina, Incorporated's (the Company) Annual Report on Form 10-K for the year
ended December 31, 2000. These are interim financial statements, and due to the
seasonality of the Company's business, the amounts reported in the Condensed
Consolidated Statements of Income(Loss) are not necessarily indicative of
amounts expected for the year. In the opinion of management, the information
furnished herein reflects all adjustments, all of a normal recurring nature
except as described in Notes 2, 3, 4 and 5, which are necessary for a fair
statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This accounting standard requires
cost-based rate-regulated utilities to recognize in their financial
statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result the Company has
recorded, as of June 30, 2001, approximately $17 million and $10
million of regulatory assets and liabilities, respectively, including
amounts recorded for deferred income tax liabilities of approximately
$0.2 million. The regulatory assets are recoverable through rates. In
the future, as a result of deregulation or other changes in the
regulatory environment, the Company may no longer meet the criteria for
continued application of SFAS 71 and could be required to write off its
regulatory assets and liabilities. Such an event could have a material
adverse effect on the Company's results of operations in the period the
write-off would be recorded, but it is not expected that cash flows or
financial position would be materially affected.
B. New Accounting Standards
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. The
Company's adoption of SFAS 133, as amended, did not have a material
impact on the Company's results of operations, cash flows or financial
position.
In June 2001 the Financial Accounting Standards Board approved the
issuance of three new accounting standards. SFAS 141, "Business
Combinations," requires that all business combinations be accounted for
using the purchase method of accounting. SFAS 141 applies to all
business combinations initiated after June 30, 2001, and is not
expected to have any impact on the Company's results of operations,
cash flows or financial position.
SFAS 142, "Goodwill and Other Intangible Assets," requires that
goodwill not be amortized but instead be tested for impairment at least
annually at the reporting unit level. A reporting unit is the same
level as, or one level below, an operating segment. The Companywill
adopt SFAS 142 effective January 1, 2002. The impact SFAS 142 may have
on the Company's results of operations, cash flows or financial
position has not been determined but could be material.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset. The Company will adopt SFAS 143
effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows and financial position has
not been determined.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2001.
2. CUMULATIVE EFFECT OF ACCOUNTING CHANGE
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues from cycle billing to full accrual. The
cumulative effect of this change was $6.6 million, net of tax. Accruing
unbilled revenues more closely matches revenues and expenses. Unbilled
revenues represent the estimated amount customers will be charged for
service rendered but not yet billed as of the end of the accounting
period. Also, effective January 1, 2000 the gas costs associated with
unbilled revenues are no longer deferred.
3. ACQUISITION BY SCANA CORPORATION
On February 10, 2000 the acquisition of the Company by SCANA
Corporation (SCANA) was consummated in a business combination accounted
for as a purchase. As a result the Company became a wholly owned
subsidiary of SCANA. Pursuant to the Agreement and Plan of Merger, the
Company shareholders were paid approximately $212 million in cash and
17.4 million shares of SCANA common stock valued at approximately $488
million.
The Company has recorded a utility plant acquisition adjustment of
approximately $466 million, which reflects the excess of SCANA's
purchase price of approximately $700 million over the fair value of the
Company's net assets at January 1, 2000. The adjustment is being
amortized over 35 years on a straight-line basis. Common equity at June
30, 2001 and December 31, 2000 reflects the effects of this acquisition
adjustment.
The Company agreed to pay approximately $5 million to ten key
executives under severance agreements related to the acquisition.
Severance benefits of approximately $2.7 million have been paid to
seven key executives whose positions were eliminated. In addition,
approximately $3.1 million was paid to former directors of the Company
in connection with deferred compensation and retirement plans, and
approximately $8.1 million was paid to participants in the Company's
nonqualified stock option plans.
4. SALE OF PSNC PRODUCTION CORPORATION AND SCANA PUBLIC SERVICE LLC
PSNC Production Corporation and SCANA Public Service Company LLC were
sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, for $4.4
million, which approximated net book value, effective January 1, 2001.
5. RATE AND OTHER REGULATORY MATTERS
On April 6, 2000 the North Carolina Utilities Commission (NCUC) issued
an order permanently approving the Company's request to establish its
commodity cost of gas for large commercial and industrial customers on
the basis of market prices for natural gas. The NCUC previously allowed
the Company use of this mechanism on a trial basis. This mechanism
allows the Company to collect from its customers amounts approximating
the amounts paid for natural gas.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from the Company's interstate
pipeline transporters, provides financing for expansion into areas that
otherwise would not be economically feasible to serve. On December 30,
1999 the Company filed an application with the NCUC to extend natural
gas service to Madison, Jackson and Swain Counties, North Carolina.
Pursuant to state statutes, the NCUC required the Company to forfeit
its exclusive franchises to serve six counties in western North
Carolina effective January 31, 2000 because these counties were not
receiving any natural gas service. Madison, Jackson and Swain Counties
were included in the forfeiture order. On June 29, 2000 the NCUC
approved the Company's requests for reinstatement of its exclusive
franchises for Madison, Jackson and Swain Counties and disbursement of
up to $28.4 million from the Company's expansion fund for this project.
The Company estimates that the cost of this project will be
approximately $31.4 million. The Madison County portion of the project
was completed at a cost of approximately $4.8 million and customers
began receiving service in July 2001.
On December 7, 1999 the NCUC issued an order approving the
acquisition of the Company by SCANA. As specified in the NCUC order,
the Company reduced its rates by approximately $1 million in each of
August 2000 and August 2001, and has agreed to a moratorium on general
rate cases until August 2005. General rate relief can be obtained
during this period to recover costs associated with materially adverse
governmental actions and force majeure events.
6. LONG-TERM DEBT
On February 16, 2001 the Company issued $150 million of medium-term
notes having an annual interest rate of 6.625 percent and maturing on
February 15, 2011. The proceeds were used to reduce short-term debt and
for general corporate purposes.
7. CONTINGENCIES
The Company owns, or has owned, all or portions of seven sites in North
Carolina on which manufactured gas plants (MGPs) were formerly
operated. Intrusive investigation (including drilling, sampling and
analysis) has begun at two sites and the remaining sites have been
evaluated using historical records and observations of current site
conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. The North Carolina
Department of Environment and Natural Resources (DENR) has recommended
that no further action be taken with respect to one site. Excavation at
the Raleigh MGP site was completed in March 2001 as part of an Interim
Removal Action. Further work may be required at the discretion of DENR.
Work at the Durham MGP site began in May 2001 under a DENR-approved
Phase II Workplan. An environmental due diligence review of the Company
conducted in February 1999 estimated that the cost to remediate the
remaining sites would range between $11.3 million and $21.9 million.
During the second quarter of 2000, the review was finalized and the
estimated liability was recorded. The Company is unable to determine
the rate at which costs may be incurred over this time period. The
estimated cost range has not been discounted to present value. The
Company's associated actual costs for these sites will depend on a
number of factors, such as actual site conditions, third-party claims
and recoveries from other PRPs. A May 1993 order by the NCUC authorized
deferral accounting for all costs associated with the investigation and
remediation of MGP sites. As of June 30, 2001 the Company has recorded
a liability and associated regulatory asset of $9.2 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 million. Management intends to
request recovery of additional MGP clean-up costs not recovered from
other PRPs in future rate case filings, and believes that all costs
incurred will be recoverable in gas rates.
8. SEGMENT OF BUSINESS INFORMATION
For the three and six months ended June 30, 2001 Gas Distribution is
the Company's only reportable segment. Gas Distribution uses operating
income to measure profitability. Effective January 1, 2001 PSNC
Production Corporation and SCANA Public Service Company LLC (SCANA
Public Service) were sold to SCANA Energy Marketing, Inc., a subsidiary
of SCANA (see Note 4). In 2000 SCANA Public Service was an Energy
Marketing segment of the Company and used net income to measure
profitability.
Disclosure of Reportable Segments
(Millions of Dollars)
- ------------------------------------------------ --------- --------------- --------------------
Three months ended Gas Energy All Adjustments/ Consolidated
June 30, 2001 Distribution Marketing Other Eliminations Total
- ------------------------------------------------ --------- --------------- --------------------
External Revenue 67 n/a - - 67
Intersegment Revenue - n/a - - -
Operating Income(Loss) (2) n/a n/a - (2)
Segment Assets 1,179 n/a 29 (26) 1,182
------------------------- ------------------- ------------------ ------------- --------------------- --------------------
Three months ended Gas Energy All Adjustments/ Consolidated
June 30, 2000 Distribution Marketing Other Eliminations Total
------------------------- ------------------- ------------------ ------------- --------------------- --------------------
External Revenue 55 25 - - 80
Intersegment Revenue - - - - -
Operating Income(Loss) (2) n/a n/a - (2)
Net Income n/a - 1 (6) (5)
Segment Assets 1,112 20 59 (58) 1,133
------------------------- ------------------- ------------------ ------------- --------------------- --------------------
Six months ended Gas Energy All Adjustments/ Consolidated
June 30, 2001 Distribution Marketing Other Eliminations Total
------------------------- ------------------- ------------------ ------------- --------------------- --------------------
External Revenue 295 n/a - - 295
Intersegment Revenue - n/a n/a - -
Operating Income 37 n/a n/a - 37
Segment Assets 1,179 n/a 29 (26) 1,182
------------------------- ------------------- ------------------ ------------- --------------------- --------------------
Six months ended Gas Energy All Adjustments/ Consolidated
June 30, 2000 Distribution Marketing Other Eliminations Total
------------------------- ------------------- ------------------ ------------- --------------------- --------------------
External Revenue 221 55 - (26) 250
Intersegment Revenue - 2 29 (31) -
Operating Income 33 n/a n/a 2 35
Net Income n/a 1 3 17 21
1
Segment Assets 1,112 20 59 (58) 1,133
1 Includes cumulative effect of accounting change (See Note 2).
Item 2. Management's Narrative Analysis of Results of Operations.
---------------------------------------------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion should be read in conjunction with
Management's Narrative Analysis of Results of Operations appearing in Public
Service Company of North Carolina, Incorporated's (PSNC) Annual Report on Form
10-K for the year ended December 31, 2000.
Statements included in this narrative analysis (or elsewhere in this
quarterly report) which are not statements of historical fact are intended to
be, and are hereby identified as, forward-looking statements for purposes of the
safe harbor provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are
cautioned that such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties, and that actual
results could differ materially from those indicated by such forward-looking
statements. Important factors that could cause actual results to differ
materially from those indicated by such forward-looking statements include, but
are not limited to, the following: (1) that the information is of a preliminary
nature and may be subject to further and/or continuing review and adjustment,
(2) changes in the utility regulatory environment, (3) changes in the economy,
especially in PSNC's service territory, (4) the impact of competition from other
energy suppliers, (5) growth opportunities, (6) the results of financing
efforts, (7) changes in PSNC's accounting policies, (8) weather conditions,
especially in areas served by PSNC, (9) inflation, (10) changes in environmental
regulations and (11) the other risks and uncertainties described from time to
time in PSNC's periodic reports filed with the Securities and Exchange
Commission. PSNC disclaims any obligation to update any forward-looking
statements.
Capital Expansion Program
PSNC's capital expansion program, through the construction of lines,
services, systems and facilities, and the purchase of equipment, is designed to
help PSNC meet the growing demand for natural gas in its franchised service
areas. PSNC's 2001 construction budget is approximately $58.0 million, compared
to actual construction expenditures for 2000 of $39.1 million. The construction
program is reviewed regularly by management and is dependent upon PSNC's
continuing ability to generate adequate funds internally and to sell new issues
of debt on acceptable terms. Construction expenditures during the six months
ended June 30, 2001 were $28.9 million compared to $15.0 million for the same
period last year. PSNC's ratio of earnings to fixed charges for the 12 months
ended June 30, 2001 was 3.0.
Earnings and Dividends
Net income for the six months ended June 30, 2001 and 2000 was as
follows:
------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2001 2000
---------------------------------------------------------------- -------------
Net income derived from:
Operations $15.6 $14.2
Cumulative effect of change in accounting - 6.6
---------------------------------------------------------------- -------------
Total net income $15.6 $20.8
================================================================ =============
Net income from operations for the six months ended June 30, 2001
increased $1.4 million over the corresponding period in 2000 primarily due to
customer growth and a decrease in operating and maintenance expenses. In 2000
net income reflects a change in accounting to record unbilled revenues (see Note
2 of Notes to Condensed Consolidated Financial Statements).
PSNC's Board of Directors declared the following quarterly dividends on common
stock held by SCANA during 2001:
- --------------------- -------------------- --------------------- ---------------
Declaration Date Dividend Amount Quarter Ended Payment Date
- --------------------- -------------------- --------------------- ---------------
February 22, 2001 $6.0 million March 31, 2001 April 1, 2001
May 3, 2001 $5.8 million June 30, 2001 July 1, 2001
August 2, 2001 $3.0 million September 30, 2001 October 1, 2001
- --------------------- -------------------- --------------------- ---------------
Gas Distribution
Changes in gas distribution sales margins for the six months ended June
30, 2001, when compared to the corresponding period in 2000, were as follows:
---------------------------- ------------------------------------------------
Six Months Ended June 30,
Millions of dollars 2001 2000 Change
---------------------------- ------------ ---------- ------------------------
Gas operating revenue $295.6 $249.8 $45.8 18.3%
Less: Cost of gas 202.3 155.9 46.4 29.8%
---------------------------- ------------ ---------- --------------
Gross margin $93.3 $93.9 $(0.6) (0.6%)
============================ ============ ========== ========================
The decrease in margin for six months ended June 30, 2001 is primarily
due to lower natural gas usage per degree day and the sale of PSNC Production
Corporation (see Note 4 of Notes to Condensed Consolidated Financial
Statements). This decrease was partially offset by a 2.8 percent increase in
customers. Customers as of June 30, 2001 and 2000 were approximately 362,000 and
352,000, respectively. Revenues and cost of gas were impacted by large increases
in natural gas prices in late 2000 and early 2001.
Operating Expenses
Operating and maintenance expenses for the six months ended June 30,
2001 decreased $2.7 million when compared to the corresponding period in 2000.
This decrease is primarily due to reduced costs related to employee benefits and
advertising. The decrease also reflects the sale of PSNC Production Corporation.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
SCANA Corporation:
For information regarding legal proceedings see Note 4 "Rate and Other
Regulatory Matters," of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2000, and Note 4 "Rate and Other Regulatory Matters"
and Note 9 "Contingencies" of NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS appearing in this Quarterly Report on Form 10-Q.
South Carolina Electric & Gas Company:
For information regarding legal proceedings see Note 3 "Rate and Other
Regulatory Matters," of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
appearing in South Carolina Electric & Gas Company's Annual Report on
Form 10-K for the year ended December 31, 2000, and Note 3 "Rate and
Other Regulatory Matters" and Note 6 "Contingencies" of NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS appearing in this Quarterly
Report on Form 10-Q.
Public Service Company of North Carolina, Incorporated:
For information regarding legal proceedings see Note 5 "Rate and Other
Regulatory Matters," of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
appearing in Public Service Company of North Carolina, Incorporated's
Annual Report on Form 10-K for the year ended December 31, 2000, and
Note 5 "Rate and Other Regulatory Matters" and Note 7 "Contingencies"
of NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS appearing in
this Quarterly Report on Form 10-Q.
Item 4. Submission of Matters to a Vote of Security-Holders (not applicable
for South Carolina Electric & Gas Company and Public Service Company of North
Carolina, Incorporated)
- -----------------------------------------------------------------------
The Annual Meeting of Shareholders of SCANA Common Stock (No Par Value)
was held on May 3, 2001. The following matters were voted upon at the
meeting.
1. To elect five (5) directors for the terms specified in the Proxy Statement.
Number of Voting Number of Shares Total
Shares Voting Voting to Shares
Nominee For Withhold Authority Voted
William B. Bookhart 92,521,398 1,340,525 93,861,923
Elaine T. Freeman 92,389,031 1,472,892 93,861,923
Harold C. Stowe 92,466,414 1,395,509 93,861,923
W. Hayne Hipp 92,474,351 1,387,572 93,861,923
G. Smedes York 92,416,809 1,445,114 93,861,923
2. To approve the appointment of Deloitte & Touche as independent
accountants for the Corporation.
Number
of Shares
For 92,573,278
Against 766,339
Abstain 522,306
-----------
Total 93,861,923
Percent of FOR votes of those shares actually voting for this proposal: 98.6%
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits
SCANA Corporation, South Carolina Electric & Gas Company and
Public Service Company of North Carolina, Incorporated:
Exhibits filed with this Quarterly Report on Form 10-Q are
listed in the following Exhibit Index. Certain of such exhibits
which have heretofore been filed with the Securities and
Exchange Commission and which are designated by reference to
their exhibit numbers in prior filings are hereby incorporated
herein by reference and made a part hereof.
B. Reports on Form 8-K during the second quarter 2001 were as follows:
SCANA Corporation:
Date of report: May 31, 2001
Item reported: Item 2
South Carolina Electric & Gas Company: None
Public Service Company of North Carolina, Incorporated: None
SCANA CORPORATION
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SCANA CORPORATION
(Registrant)
August 14, 2001 By: s/M. R. Cannon
--------------------
M. R. Cannon
Controller
(Principal accounting officer)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
-------------------------------------
(Registrant)
August 14, 2001 By: s/Mark R. Cannon
---------------------------------
Mark R. Cannon
Controller
(Principal accounting officer)
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
(Registrant)
August 14, 2001 By: s/Mark R. Cannon
---------------------------------
Mark R. Cannon
Controller
(Principal accounting officer)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
2.01 X X Agreement and Plan of Merger, dated as of February
16, 1999 as amended and restated as of May 10,
1999, by and among Public Service Company of North
Carolina, Incorporated, SCANA Corporation, New Sub
I, Inc. and New Sub II, Inc. (Filed as Exhibit 2.1
to Registration Statement No. 333-78227 on Form
S-4)
3.01 X Restated Articles of Incorporation of SCANA as
adopted on April 26, 1989 (Filed as Exhibit 3-A to
Registration Statement No. 33-49145)
3.02 X Restated Articles of Incorporation of SCE&G, as
adopted on May 3, 2001 (Filed as Exhibit 3.01 to
Registration Statement No. 333-65460)
3.03 X Articles of Amendment of SCANA, dated April 27,
1995 (Filed as Exhibit 4-B to Registration
Statement No. 33-62421)
3.04 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)
3.05 X Articles of Amendment of PSNC (formerly New Sub II,
Inc.) as adopted on February 10, 2000 (Filed as
Exhibit 3.02 to Registration Statement No.
333-45206)
3.06 X Articles of Correction of PSNC dated February 11,
2000 (Filed as Exhibit 3.03 to Registration
Statement No. 333-45206)
3.07 X By-Laws of SCANA as revised and amended on December
13, 2000 (Filed as Exhibit 3.22 to Form 10-K for
the year ended December 31, 2000)
3.08 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)
3.09 X By-Laws of PSNC (formerly New Sub II, Inc.) as
revised and amended on February 22, 2001 (Filed as
Exhibit 3.24 to Form 10-K for the year ended
December 31, 2000)
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 (Exhibit 2-C to
Registration Statement No. 2-26459)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
4.05 X X
Fifth through Fifty-third Supplemental Indenture referred to in Exhibit 4.03
dated as of the dates indicated below and filed as exhibits to the
Registration Statements whose file numbers are set forth below
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-O to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 2-B to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 2-A-3 to Registration No. 33-38580
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
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
February 1, 1987 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
February 1, 1991 Exhibit 4-D to Registration No. 33-49421
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
May 1, 1999 Exhibit 4.04 to Registration No. 333-86387
4.06 X X Indenture dated as of April 1, 1993 from South
Carolina Electric & Gas Company to NationsBank of
Georgia, National Association (Filed as Exhibit 4-F
to Registration Statement No. 33-49421)
4.07 X X First Supplemental Indenture to Indenture referred
to in Exhibit 4.06 dated as of June 1, 1993 (Filed
as Exhibit 4-G to Registration Statement No.
33-49421)
4.08 X X Second Supplemental Indenture to Indenture referred
to in Exhibit 4.06 dated as of June 15, 1993 (Filed
as Exhibit 4-G to Registration Statement No.
33-57955)
4.09 X X Trust Agreement for SCE&G Trust I (Filed as Exhibit
4.03 to Registration Statement No. 333-49960)
4.10 X X Certificate of Trust of SCE&G Trust I (Filed as
Exhibit 4.04 to Registration Statement No.
333-49960)
4.11 X X Junior Subordinated Indenture for SCE&G Trust I
(Filed as Exhibit 4.05 to Registration Statement
No. 333-49960)
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as
Exhibit 4.06 to Registration Statement No. 333-49960)
4.13 X X Amended and Restated Trust Agreement for SCE&G Trust
I (Filed as Exhibit 4.07 to Registration Statement
No. 333-49960)
4.14 X X Indenture dated as of January 1, 1996 between PSNC
and First Union National Bank of North Carolina, as
Trustee (Filed as Exhibit 4.08 to Registration
Statement No. 333-45206 and incorporated by reference
herein)
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 and
incorporated by reference herein)
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 and
incorporated by reference herein)
4.17 X X Third Supplemental Indenture dated as of February 10,
2000 between PSNC and First Union National Bank of
North Carolina, as Trustee (Filed as Exhibit 4.11
to Registration Statement No. 333-45206 and
incorporated by reference herein)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
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 4.28 to Form 10-K
for the year ended December 31, 2000)
4.19 X PSNC $150 million medium-term
note issued February 16, 2001
(Filed as Exhibit 4.29 to Form
10-K for the year ended December
31, 2000)
10.01 X SCANA Voluntary Deferral Plan as amended
through October 21, 1997 (Filed as
Exhibit 10.01 to Registration Statement No.
333-49960)
10.02 X SCANA Supplementary Executive Retirement Plan
as amended and restated effective
as of October 21, 1997 (Filed as Exhibit 10.01
(b) to Registration Statement No.
333-86803)
10.03 X SCANA Supplementary Voluntary Deferral Plan as
amended and restated through October 21, 1997
(Filed as Exhibit 10.02 to Registration
Statement No.333-49960)
10.04 X SCANA Key Executive Severance Benefits Plan as
amended and restated effective as of October
21, 1997 (Filed as Exhibit 10.01(c) to
Registration Statement No. 333-86803)
10.05 X SCANA Supplementary Key Executive Severance
Benefits Plan effective as of December 17,
1997 (Filed as Exhibit 10.01(d) to
Registration Statement No.
333-86803)
10.06 X SCANA Performance Share Plan as amended and
restated effective January 1, 1998
(Filed as Exhibit 10 (e) to Registration
Statement No. 333-86803)
10.07 X SCANA Long-Term Equity Compensation Plan dated
January 2000 filed as Exhibit
4.04 to Registration Statement No. 333-37398)
10.08 X SCANA Key Employee Retention Plan as amended
and restated effective as of October 21, 1997
(Filed as Exhibit 10.02 to Registration
Statement No. 333-49960)
10.09 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)
10.10 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)
10.11 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
10.12 X Operating Agreement of Pine Needle LNG Company,
LLC dated August 8, 1995 (Filed as Exhibit
10.01 to Registration Statement No. 333-45206)
10.13 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)
10.14 X Amended Operating Agreement of Cardinal Extension
Company, LLC dated December 19, 1996 (Filed as
Exhibit 10.03 to Registration Statement No.
333-45206)
10.15 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)
10.16 X Form of Severance Agreement between PSNC and its
Executive Officers (Filed as Exhibit 10.05 to
Registration Statement No. 333-45206)
10.17 X Service Agreement between PSNC and SCANA Services,
Inc., effective April 1, 2000 (Filed as Exhibit
10.06 to Registration Statement No. 333-45206)