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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 Quarter Ended September 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(A South Carolina Corporation)
1426 Main Street
Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
(A South Carolina Corporation)
1426 Main Street
Columbia, South Carolina 29201
(803) 217-9000
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
Description of Shares Outstanding
Registrant Common Stock at October 31, 1999
SCANA Corporation Without Par Value 103,572,623
South Carolina Electric Par Value $4.50 Per Share 40,296,1471
& Gas Company
1Held, beneficially and of record, by SCANA Corporation.
This combined Form 10-Q is separately filed by SCANA Corporation and
South Carolina Electric & Gas Company. Information contained herein relating to
SCANA Corporation or any of its direct or indirect subsidiaries, other than
South Carolina Electric & Gas Company and its consolidated operations, is
provided solely by SCANA Corporation and shall be deemed not included in the
Form 10-Q of South Carolina Electric & Gas Company.
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<PAGE>
INDEX
Page
PART 1. FINANCIAL INFORMATION
SCANA Corporation Financial Section........................................... 3
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 1999 and December 31, 1998.... 4
Consolidated Statements of Income and Retained Earnings for the Periods
Ended September 30, 1999 and 1998............................................ 6
Consolidated Statements of Cash Flows for the Periods Ended September
30, 1999 and 1998........................................................... 7
Notes to Consolidated Financial Statements.................................... 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.............................................14
Item 3. Quantitative and Qualitative Disclosures About Market Risk............22
South Carolina Electric & Gas Company Financial Section.......................23
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 1999 and December 31, 1998....24
Consolidated Statements of Income and Retained Earnings for the
Periods Ended September 30, 1999 and 1998....................................26
Consolidated Statements of Cash Flows for the Periods Ended September
30, 1999 and 1998............................................................27
Notes to Consolidated Financial Statements....................................28
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................32
Item 3. Quantitative and Qualitative Disclosures About Market Risk............39
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.....................................................40
Item 4. Submission of Matters to a Vote of Security-Holders...................40
Item 6. Exhibits and Reports on Form 8-K......................................40
Signatures....................................................................41
Exhibit Index.................................................................43
<PAGE>
SCANA CORPORATION
FINANCIAL SECTION
<PAGE>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
SCANA CORPORATION
CONSOLIDATED BALANCE SHEETS
As of September 30, 1999 and December 31, 1998
(Unaudited)
September 30, December 31,
- ------------------------------------------------------------------------
1999 1998
- ------------------------------------------------------------------------
Assets (Millions of Dollars)
Utility Plant:
Electric $4,470 $4,406
Gas 614 604
Other 180 175
- ------------------------------------------------------------------------
Total 5,264 5,185
Less accumulated depreciation and amortization 1,835 1,728
- ------------------------------------------------------------------------
Total 3,429 3,457
Construction work in progress 328 251
Nuclear fuel, net of accumulated amortization 48 56
Acquisition adjustment-gas, net of
accumulated amortization 23 23
- ------------------------------------------------------------------------
Utility Plant, Net 3,828 3,787
- ------------------------------------------------------------------------
Nonutility Property and Investments, net of
accumulated depreciation 796 493
- ------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments 57 62
Receivables 280 276
Inventories (at average cost):
Fuel 55 63
Materials and supplies 75 56
Prepayments 29 22
Deferred income taxes 20 22
- -------------------------------------------------------------------------
Total Current Assets 516 501
- -------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 25 22
Nuclear plant decommissioning fund 62 56
Pension asset, net 136 115
Other regulatory assets 185 216
Other 106 60
- ------------------------------------------------------------------------
Total Deferred Debits 545 500
- ------------------------------------------------------------------------
Total $5,685 $5,281
========================================================================
<PAGE>
SCANA CORPORATION
CONSOLIDATED BALANCE SHEETS
As of September 30, 1999 and December 31, 1998
(Unaudited)
September 30, December 31,
- --------------------------------------------------------------------------------
1999 1998
- --------------------------------------------------------------------------------
Capitalization and Liabilities (Millions of Dollars)
Stockholders' Investment:
Common Equity $1,922 $1,746
Preferred stock (not subject to purchase
or sinking funds) 106 106
- --------------------------------------------------------------------------------
Total Stockholders' Investment 2,028 1,852
Preferred Stock, Net (subject to purchase or
sinking funds) 11 11
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 1,610 1,623
- --------------------------------------------------------------------------------
Total Capitalization 3,699 3,536
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 162 195
Current portion of long-term debt 327 107
Accounts payable 142 219
Customer deposits 18 18
Taxes accrued 92 72
Interest accrued 37 28
Dividends declared 31 42
Other 15 13
- --------------------------------------------------------------------------------
Total Current Liabilities 824 694
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes 733 628
Deferred investment tax credits 105 108
Postretirement benefits 95 87
Reserve for nuclear plant decommissioning 62 56
Other regulatory liabilities 75 71
Other 92 101
- --------------------------------------------------------------------------------
Total Deferred Credits 1,162 1,051
- --------------------------------------------------------------------------------
Total $5,685 $5,281
================================================================================
See Notes to Consolidated Financial Statements.
<TABLE>
<CAPTION>
<PAGE>
SCANA CORPORATION
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Periods Ended September 30, 1999 and 1998
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------ --------------- ------------- --------------
1999 1998 1999 1998
- ------------------------------------------------------------ --------------- ------------- --------------
(Millions of Dollars, Except Per Share Amounts)
Operating Revenues:
<S> <C> <C> <C> <C>
Electric 393 $ 393 $ 953 $ 962
Gas 87 81 299 305
Transit - - 1 1
- ------------------------------------------------------------ --------------- ------------- --------------
Total Operating Revenues 480 474 1,253 1,268
- ------------------------------------------------------------ --------------- ------------- --------------
Operating Expenses:
Fuel used in electric generation 87 84 221 212
Purchased power 14 9 29 22
Gas purchased for resale 64 54 200 199
Other operation 66 66 186 186
Maintenance 25 21 64 62
Depreciation and amortization 42 39 126 107
Income taxes 47 55 96 117
Other taxes 26 26 79 78
- ------------------------------------------------------------ --------------- ------------- --------------
Total Operating Expenses 371 354 1,001 983
- ------------------------------------------------------------ --------------- ------------- --------------
Operating Income 109 120 252 285
- ------------------------------------------------------------ --------------- ------------- --------------
Other Income:
Allowance for equity funds used during
construction - 2 3 6
Other income (loss), net of income taxes (3) (1) (14) 1
- ------------------------------------------------------------ --------------- ------------- --------------
Total Other Income (Loss) (3) 1 (11) 7
- ------------------------------------------------------------ --------------- ------------- --------------
Income Before Interest Charges And Preferred
Stock Dividends 106 121 241 292
- ------------------------------------------------------------ --------------- ------------- --------------
Interest Charges (Credits):
Interest expense on long-term debt 34 31 97 89
Other interest expense 3 3 11 8
Allowance for borrowed funds used during
construction (1) (2) (3) (5)
- ------------------------------------------------------------ --------------- ------------- --------------
Total Interest Charges, Net 36 32 105 92
- ------------------------------------------------------------ --------------- ------------- --------------
Income Before Preferred Dividend Requirements
on Mandatorily Redeemable Preferred Securities 70 89 136 200
Preferred Dividend Requirement of SCE&G -
Obligated Mandatorily
Redeemable Preferred Securities 1 1 3 3
- ------------------------------------------------------------ --------------- ------------- --------------
Income Before Preferred Stock Cash Dividends
of Subsidiary 69 88 133 197
Preferred Stock Cash Dividends of Subsidiary
(At Stated Rates) 2 2 5 5
- ------------------------------------------------------------ --------------- ------------- --------------
Net Income 67 86 128 192
Retained Earnings at Beginning of Period 659 641 678 617
Common Stock Cash Dividends Declared (28) (40) (108) (122)
============================================================ =============== ============= ==============
Retained Earnings at End of Period $ 698 $ 687 $ 698 $ 687
============================================================ =============== ============= ==============
Net Income $ 67 $ 86 $ 128 $ 192
Weighted Average Number of Common Shares
Outstanding (Millions) 103.6 104.2 103.6 105.9
Earnings Per Weighted Average Share of
Common Stock (Basic and Diluted) $ .65 $ .82 $ 1.23 $ 1.81
Cash Dividends Declared Per Share of
Common Stock $ .275 $ .385 $ 1.045 $ 1.155
========================================================== =============== ============= ==============
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
SCANA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Periods Ended September 30, 1999 and 1998
(Unaudited)
Nine Months Ended
September 30,
- ------------------------------------------------------------------ -------------
1999 1998
- ------------------------------------------------------------------ -------------
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $128 $192
Adjustments to reconcile net income to net
cash provided from operating activities:
Depreciation and amortization 133 113
Amortization of nuclear fuel 13 15
Deferred income taxes, net 10 17
Pension asset (21) (18)
Other regulatory assets 31 7
Other regulatory liabilities 4 5
Post-retirement benefits 8 22
Allowance for funds used during construction (6) (12)
Over (under) collections, fuel adjustment clause (8) (1)
Deferred taxes - unrealized gain on investments (97) (11)
Changes in certain current assets and liabilities
(Increase) decrease in receivables (4) (35)
(Increase) decrease in inventories (11) 4
(Increase) decrease in prepayments (7) (6)
Increase (decrease) in accounts payable (77) 13
Increase (decrease) in taxes accrued 20 28
Other, net 54 4
- ------------------------------------------------------------------ -------------
Net Cash Provided From Operating Activities 170 337
- ------------------------------------------------------------------ -------------
Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (167) (161)
Increase in other property and investments (73) (87)
Sale of subsidiary assets 17 -
- ------------------------------------------------------------------ -------------
Net Cash Used For Investing Activities (223) (248)
- ------------------------------------------------------------------ -------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 99 -
Issuance of notes and loans 150 135
Repayments:
First and Refunding Mortgage Bonds - (20)
Notes and loans (44) (80)
Other long-term debt (9) (5)
Preferred stock - (1)
Repurchase of common stock - (110)
Dividend payments:
Common stock (120) (122)
Preferred stock of subsidiary (6) (6)
Short-term borrowings, net (33) 122
Fuel and emission allowance financings, net 11 (10)
- ------------------------------------------------------------------ -------------
Net Cash Provided From Financing Activities 48 (97)
- ------------------------------------------------------------------ -------------
Net Increase (Decrease) In Cash And Temporary
Cash Investments (5) (8)
Cash And Temporary Cash Investments At January 1 62 60
- ------------------------------------------------------------------ -------------
Cash And Temporary Cash Investments At September 30 $ 57 $ 52
================================================================== =============
Supplemental Cash Flow Information:
Cash paid for - Interest (includes capitalized
interest of $3 for 1999 and $5 for 1998) $ 97 $ 87
- Income taxes 37 59
Noncash investing activities
- Unrealized gain on securities
available for sale (net of tax) 157 19
See Notes to Consolidated Financial Statements.
<PAGE>
SCANA CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1999
(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, 1998. These are
interim financial statements, and the amounts reported in the Consolidated
Statements of Income are not necessarily indicative of amounts expected for the
year. In the opinion of management, the information furnished herein reflects
all adjustments, all of a normal recurring nature except as described in Note 2,
which are necessary for a fair statement of the results for the interim periods
reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards No. 71 (SFAS 71). The accounting standard requires
cost-based rate-regulated utilities to recognize in their financial
statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result the Company has
recorded, as of September 30, 1999, approximately $210 million and $75
million of regulatory assets and liabilities, respectively, including
amounts recorded for deferred income tax assets and liabilities of
approximately $130 million and $56 million, respectively. The electric
and gas regulatory assets (excluding deferred income tax assets) of
approximately $45 million and $33 million, respectively, are being
recovered through rates, and the Public Service Commission of South
Carolina (PSC) has approved accelerated recovery of approximately $9
million of the electric regulatory assets. 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 that a write-off would be required,
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 of the Company totaled $143 million
and $284 million for the three and nine months ended September 30, 1999,
respectively, and $70 million and $210 million for the same periods in
1998. For each period, comprehensive income included net income and
unrealized gains/losses on securities available for sale.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the 1999 presentation.
2. RATE MATTERS
On December 11, 1998, the PSC issued an order requiring South Carolina
Electric & Gas Company (SCE&G), a wholly-owned subsidiary of the
Company, to reduce retail electric rates on a prospective basis. The PSC
acted in response to SCE&G reporting that it earned a 13.04 percent
return on common equity for its retail electric operations for the
twelve months ended September 30, 1998. This return on common equity
exceeded SCE&G's authorized return of 12 percent by 1.04 percent, or
$22.7 million, primarily as a result of record heat experienced during
the summer. The order required prospective rate reductions on a per
kilowatt-hour basis, based on actual retail sales for the twelve months
ended September 30, 1998. This action will reduce future reported return
on common equity to the PSC-authorized level if SCE&G experiences the
same weather effect and other business results as that of the twelve
months ended September 30, 1998. On January 12, 1999, the PSC denied
SCE&G's motion for reconsideration and reaffirmed SCE&G's return on
equity of 12 percent. The rate reductions were placed into effect with
the first billing cycle of January 1999.
<PAGE>
3. RETAINED EARNINGS:
The Restated Articles of Incorporation of the Company 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, the Federal Power Act requires the
appropriation of a portion of certain earnings from hydroelectric
projects. At September 30, 1999, approximately $28.5 million of retained
earnings were restricted by this requirement as to payment of cash
dividends on SCE&G's common stock.
4. INVESTMENTS IN EQUITY SECURITIES:
At September 30, 1999, SCANA Communications, Inc. (SCI), a wholly-owned
subsidiary of the Company, held the following investments in ITC Holding
Company, Inc. (ITC) and its affiliates:
o Powertel, Inc. (Powertel) is a publicly traded company that owns and
operates personal communications services (PCS) systems in several major
Southeastern markets. SCI owned approximately 4.9 million common shares of
Powertel. SCI's investment in Powertel's common shares of approximately
$71.6 million had a market value of $267.5 million at September 30, 1999,
resulting in a pre-tax unrealized holding gain of $195.9 million. The
after-tax amount of such gain is included in the balance sheet as a
component of "Common Equity." In addition, SCI owned the following
non-voting convertible preferred shares, at the approximate cost noted:
100,000 shares series B ($75.1 million); 50,000 shares series D ($22.5
million); and, 50,000 shares series E 6.5% ($75.0 million). Preferred
series B shares are convertible in March 2002 at a conversion price of
$16.50 per common share or approximately 4.5 million common shares.
Preferred series D shares are convertible in March 2002 at a conversion
price of $12.75 per common share or approximately 1.7 million common
shares. Preferred series E shares are convertible in June 2003 at a
conversion price of $22.01 per common share or approximately 3.4 million
common shares. The market value of the convertible preferred shares of
Powertel is not readily determinable. However, on an as converted basis,
the market value of the underlying common shares for the preferred shares
was approximately $535 million at September 30, 1999, resulting in an
unrecorded pre-tax holding gain of $362.5 million.
o ITC^ DeltaCom, Inc. (ITCD) is a fiber optic telecommunications provider.
SCI owned approximately 5.1 million common shares of ITCD. SCI's investment
in ITCD's common shares of approximately $41.2 million had a market value
of $139.0 million at September 30, 1999, resulting in a pre-tax unrealized
holding gain of $97.8 million. The after-tax amount of such gain is
included in the balance sheet as a component of "Common Equity." In
addition, SCI owned 1,480,771 shares of series A preferred stock of ITCD at
a cost of approximately $11.3 million. Series A preferred shares are
convertible in March 2002 into ITCD common shares on a two for one basis.
The market value of series A preferred stock of ITCD is not readily
determinable. However, on an as converted basis, the market value of the
underlying common stock for the series A preferred stock was approximately
$81.4 million at September 30, 1999, resulting in an unrecorded pre-tax
holding gain of $70.2 million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of cable,
television, telephone and internet services. SCI owned 71,050 units of
Knology. Each unit consists of one 11.875% Senior Discount Note due 2007
and one warrant entitling the holder to purchase .003734 shares of
preferred stock of Knology. The cost of this investment was approximately
$40 million. SCI also owned an additional 753 warrants which entitles it to
purchase 753 shares of preferred stock at $1,500 per share.
<PAGE>
o ITC has an ownership interest in several Southeastern
communications companies. SCI owned 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 $7.1 million, $8.9 million, and $5.0
million, respectively. Preferred series A shares are convertible in
March 2002 at a conversion price of $13.45 per common share or
approximately 2.6 million common shares. Preferred series B shares
are convertible in March 2002 at a conversion price of $43.56 per
common share or approximately 500,000 million common shares. The
market value of these investments is not readily determinable.
On July 9, 1999, ITCD completed its acquisition of AvData Systems, Inc.
(AvData). Prior to the merger, the Company held 1,577,384 common shares
in AvData at a cost of approximately $1.7 million. The Company received
49,995 common shares of ITCD valued at approximately $1.5 million as a
result of the merger. The Company's investment in ITCD had a market
value of $1.4 million at September 30, 1999, resulting in a pre-tax
unrealized holding loss of $0.1 million.
5. CONTINGENCIES:
With respect to commitments at September 30, 1999, reference is made to
Note 10 of Notes to Consolidated Financial Statements appearing in the
Company's Annual Report on Form 10-K for the year ended December 31,
1998. Contingencies at September 30, 1999 are as follows:
A. 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
$9.7 billion. Each reactor licensee is currently liable for up to $88.1
million per reactor owned for each nuclear incident occurring at any
reactor in the United States, provided that not more than $10 million of
the liability per reactor would be assessed per year. SCE&G's maximum
assessment, based on its two-thirds ownership of V. C. Summer Nuclear
Station (Summer Station), would be approximately $58.7 million per
incident, but not more than $6.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric Insurance Limited (NEIL) and American
Nuclear Insurers (ANI) providing combined property and decontamination
insurance coverage of $2 billion for any losses at Summer Station. SCE&G
pays annual premiums and, in addition, could be assessed a retroactive
premium not to exceed five times its annual premium in the event of
property damage loss to any nuclear generating facility covered under
the NEIL program. Based on the current annual premium, this retroactive
premium assessment would not exceed $6.1 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.
B. Environmental
The Company has 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 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. The Company has also recovered portions
of its environmental liabilities through settlements with various
insurance carriers. The Company has recovered all amounts previously
deferred for its electric operations. The Company expects to recover all
deferred amounts related to its gas operations by December 2002.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $24.3 million at September 30, 1999. The deferral
includes the estimated costs associated with the following matters.
<PAGE>
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 manufactured gas plants, 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) have
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 in 1998 at a
cost of approximately $1.5 million. Phase Two includes excavation and
installation of several permanent barriers to mitigate coal tar seepage.
Phase Two began in November 1998, and is expected to cost approximately $3
million. Additionally, SCE&G is continuing to support overall site
development activities by managing potentially contaminated soils removed
from construction activities nearby. On September 30, 1998 a Record of
Decision was issued which sets forth EPA's view of the extent of each PRP's
responsibility for site contamination and the level to which the site must
be remediated. On January 13, 1999 the EPA issued a Unilateral
Administrative Order which directed SCE&G to implement a Remedial Design
and Remedial Action Plan to accomplish the objectives identified by the
Record of Decision. SCE&G and the EPA are continuing to negotiate the
remedial plan.
In October 1996 the City of Charleston and SCE&G settled all environmental
claims the City may have had against SCE&G involving the Calhoun Park area
for a payment of $26 million over four years (1996-1999) by SCE&G to the
City. SCE&G is recovering the amount of the settlement, which does not
encompass site assessment and cleanup costs, through rates in the same
manner as other amounts accrued for site assessments and cleanup as
discussed above. As part of the environmental settlement, SCE&G has agreed
to build an 1,100 space parking garage on the Calhoun Park site and to
transfer the facility to the City in exchange for a 20-year municipal bond
backed by revenues from the parking garage and a mortgage on the parking
garage. The total amount of the bond is not to exceed $16.9 million, the
maximum expected project cost. The parking garage is currently under
construction and is scheduled for completion in the spring of the year
2000.
o SCE&G owns three other decommissioned manufactured gas plant sites which
contain residues of by-product chemicals. For the site located in Sumter,
South Carolina, effective September 15, 1998, SCE&G entered into a Remedial
Action Plan Contract with the South Carolina Department of Health and
Environmental Control (DHEC) pursuant to which it agreed to undertake a
full site investigation and remediation under the oversight of DHEC. Site
investigation and characterization are proceeding according to schedule.
Upon selection and successful implementation of a site remedy, DHEC will
give SCE&G a Certificate of Completion and a covenant not to sue. SCE&G is
continuing to investigate the other two sites, and is monitoring the nature
and extent of residual contamination.
<PAGE>
6. SEGMENT OF BUSINESS INFORMATION:
The Company's reportable segments are listed in the following table. The
Consolidated Financial Statements report operating revenues, comprised of
reportable segments, except Energy Marketing, and the non-reportable transit
operations segment. Energy Marketing's revenues and revenues from other
non-reportable segments are included in Other Income. 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 Energy Marketing segment, which
includes the Company's unregulated gas sales in Georgia. 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. Assets for the period did not change significantly.
Disclosure and Reconciliation of Reportable Segments
- --------------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30, 1999 September 30, 1998
- -------------------------------------------------------- ----------------------
Net Operating Net Operating
Income Income Income Income
(Millions of Dollars)
Electric Operations n/a $109 n/a $121
Gas Distribution n/a (2) n/a (1)
Gas Transmission $ 3 4 $ 5 6
Energy Marketing (14) n/a (3) n/a
- --------------------------------------------------------------------------------
Total Reportable Segments (11) 111 2 126
Elimination of Affiliates - (1) - (1)
Non-reportable Segments 2 (1) (3) (1)
Unallocated 76 - 87 (4)
- --------------------------------------------------------------------------------
Consolidated Totals $67 $109 $86 $120
================================================================================
External Affiliate External Affiliate
Revenue Revenue Revenue Revenue
(Millions of Dollars)
Electric Operations $393 $ 90 $393 $ 87
Gas Distribution 34 4 35 2
Gas Transmission 53 28 46 28
Energy Marketing 79 - 176 -
- --------------------------------------------------------------------------------
Total Reportable Segments $559 $122 $650 $117
================================================================================
<PAGE>
- ------------------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30, 1999 September 30, 1998
- ------------------------------------------------------------------------------
Net Operating Net Operating
Income Income Income Income
(Millions of Dollars)
Electric Operations n/a $235 n/a $263
Gas Distribution n/a 12 n/a 16
Gas Transmission $ 8 11 $ 13 15
Energy Marketing (40) n/a (7) n/a
- -------------------------------------------------------------------------
Total Reportable Segments (32) 258 6 294
Elimination of Affiliates - (3) - (4)
Non-reportable Segments - (3) (3) (3)
Unallocated 160 - 189 (2)
- -----------------------------------------------------------------------------
Consolidated Totals $128 $252 $192 $285
=============================================================================
External Affiliate External Affiliate
Revenue Revenue Revenue Revenue
(Millions of Dollars)
Electric Operations $ 953 $237 $ 962 $228
Gas Distribution 163 4 164 5
Gas Transmission 136 107 141 106
Energy Marketing 289 - 422 -
- ----------------------------------------------------------------------------
Total Reportable Segments $1,541 $348 $1,689 $339
============================================================================
<PAGE>
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, 1998.
Statements included in this discussion and analysis (or elsewhere in
this quarterly report) which are not statements of historical fact are intended
to be, and are hereby identified as, "forward-looking statements" for purposes
of the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, including the pace of deregulation of retail natural gas and
electricity markets in the United States, (3) changes in the economy, (4) the
impact of competition from other energy suppliers, (5) the management of the
Company's operations, (6) variations in prices of natural gas and fuels used for
electric generation, (7) growth opportunities for the Company's regulated and
non-regulated subsidiaries, (8) the results of financing efforts, (9) changes in
the Company's accounting policies, (10) weather conditions in the Company's
service areas , (11) performance of the telecommunications companies in which
the Company has made significant investments, (12) inflation, (13) exposure to
environmental issues and liabilities, (14) changes in environmental regulation,
(15) unsuccessful correction of any material Year 2000 problem or,
alternatively, unsuccessful implementation of a contingency plan by the Company
and any critical third party suppliers, and (16) 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.
MATERIAL CHANGES IN CAPITAL RESOURCES AND LIQUIDITY
SINCE DECEMBER 31, 1998
COMPETITION
North Carolina Acquisition
On February 17, 1999, the Company and Public Service Company of North
Carolina, Inc. (PSNC) announced a definitive agreement whereby the Company will
acquire PSNC in a transaction valued at approximately $900 million, including
the assumption of debt. The transaction will be accounted for as a purchase. It
is anticipated that PSNC will be operated as a wholly-owned subsidiary of the
Company. The shareholders of both companies approved the transaction on July 1,
1999. On July 30, 1999, SCANA filed an application with the Securities and
Exchange Commission (SEC) to become a registered public utility holding company.
The Department of Justice and the Federal Trade Commission have approved the
transaction. The North Carolina Utilities Commission held a hearing on whether
to approve the merger in late September. Their decision is expected in November.
SEC approval is expected by the end of 1999.
Georgia Retail Gas Market
SCANA Energy Marketing (Energy Marketing), a wholly-owned subsidiary of the
Company, exceeded projections for acquiring customers in Georgia's natural gas
market. At September 30, 1999, Energy Marketing had approximately 421,000
customers compared to approximately 72,000 at December 31, 1998. As a result,
expenses have been significantly higher than expected. For the nine months ended
September 30, 1999, Energy Marketing incurred losses (net of taxes) of
approximately $36.1 million. Startup costs were expensed as incurred. A
significant portion of those costs came from a $50 per customer promotional
sign-up offer, which expired April 15, 1999. Other significant costs are being
incurred to establish local offices, call centers, and billing and collection
functions. The level of future revenues and expenditures is dependent on several
factors that cannot be reasonably predicted. These factors include Energy
Marketing's ability to retain customers and market share, the intensity of
competition as it continues to develop, the margin Energy Marketing is able to
achieve on gas sales and its ability to find industrial interruptible customers
to purchase available capacity. Energy Marketing anticipates incurring
additional losses through the remainder of 1999 and plans to be breakeven for
the year 2000.
<PAGE>
Proposed Interstate Natural Gas Pipeline
On April 14, 1999, South Carolina Pipeline Corporation, a wholly-owned
subsidiary of the Company, announced plans to develop an interstate natural gas
pipeline to ensure adequate supplies to growing gas markets in South Carolina
and North Carolina. Details of the proposal are being finalized. Construction of
the project will require approval by the Federal Energy Regulatory Commission
and other federal and state agencies.
LIQUIDITY AND CAPITAL RESOURCES
On December 11, 1998, the Public Service Commission of South Carolina
(PSC) issued an order requiring South Carolina Electric & Gas Company (SCE&G), a
wholly-owned subsidiary of the Company, to reduce retail electric rates on a
prospective basis. The PSC acted in response to SCE&G reporting that it earned a
13.04 percent return on common equity for its retail electric operations for the
twelve months ended September 30, 1998. This return on common equity exceeded
SCE&G's authorized return of 12 percent by 1.04 percent, or $22.7 million,
primarily as a result of record-breaking heat experienced during the summer. The
order required prospective rate reductions on a per kilowatt-hour basis, based
on actual retail sales for the twelve months ended September 30, 1998. This
action will reduce future reported return on common equity to the PSC-authorized
level if SCE&G experiences the same weather effect and other business results as
that of the twelve months ended September 30, 1998. On January 12, 1999, the PSC
denied SCE&G's motion for reconsideration and reaffirmed SCE&G's return on
equity of 12 percent. The rate reductions were placed into effect with the first
billing cycle of January 1999.
On September 14, 1999, the PSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan will be implemented beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery methodology wherein SCE&G will 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 could be
carried forward for possible use in the succeeding year. The accelerated capital
recovery plan will be accomplished through existing customer rates.
On September 21, 1999, SCE&G announced it will build a $180 million gas
turbine generator project in Aiken County, South Carolina. The combined-cycle
turbines will burn natural gas to produce 300 megawatts of new electric
generation and then use the exhaust heat to replace coal-fired steam that powers
two existing 75 megawatt turbines at the Urquhart Generating Station. The
turbines are scheduled to be completed by June 2002.
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 remediation efforts for the dam over the past
several years as part of SCE&G's ongoing hydroelectric operating license with
FERC. Cost of the remediation project and a schedule for construction will be
determined following the expected completion of engineering and environmental
efforts in the first quarter of 2000. FERC is requiring that engineering and
construction on the dam be completed by the end of 2002.
<PAGE>
The following table summarizes how the Company generated funds for
property additions and construction expenditures during the nine months ended
September 30, 1999 and 1998:
- -------------------------------------------------------------------------------
Nine Months Ended
September 30,
1999 1998
- --------------------------------------------------------------------------------
(Millions of Dollars)
Net cash provided from operating activities $170 $337
Net cash provided from (used for) financing
activities 48 (97)
Cash provided from sale of subsidiary assets 17 -
Cash and temporary cash investments available
at the beginning of the period 62 60
===============================================================================
Net cash available for property additions
and construction $297 $300
expenditures
===============================================================================
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $167 $161
===============================================================================
Funds used for nonutility property additions $ 73 $ 87
===============================================================================
On March 9, 1999, SCE&G issued $100 million of First Mortgage Bonds
having an annual interest rate of 6 1/8% and maturing on March 1, 2009. The
proceeds from the sale of these bonds were used to reduce short-term debt.
On June 29, 1999, the Company issued $150 million one-year floating rate
medium-term notes maturing on July 14, 2000. The interest rate on the notes is
reset monthly and is based on the one-month LIBOR plus 35 basis points. The
proceeds from these notes were used to reduce short-term bank debt.
On September 28, 1999, the Company entered into a definitive agreement
to sell its retail propane assets for $86 million plus working capital
(approximately $9 million). Net proceeds from the sale will be used primarily to
reduce indebtedness. The sale was completed on November 10, 1999.
The Company anticipates that the remainder of its 1999 cash requirements
will be met through internally generated funds, and the incurrence of additional
short-term and long-term debt. The Company anticipates incurring short-term and
long-term debt to satisfy the Company's obligation to purchase shares of common
stock of SCANA and PSNC in connection with the Company's acquisition of PSNC.
The timing and amount of such financings will depend upon market conditions and
other factors. The Company expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the next twelve months and
for the foreseeable future. The ratio of earnings to fixed charges for the
twelve months ended September 30, 1999 was 2.80.
Investments in Equity Securities
At September 30, 1999, SCANA Communications, Inc. (SCI), a wholly-owned
subsidiary of the Company, held the following investments in ITC Holding
Company, Inc. (ITC) and its affiliates:
o Powertel, Inc. (Powertel) is a publicly traded company that owns and
operates personal communications services (PCS) systems in several major
Southeastern markets. SCI owned approximately 4.9 million common shares of
Powertel. SCI's investment in Powertel's common shares of approximately
$71.6 million had a market value of $267.5 million at September 30, 1999,
resulting in a pre-tax unrealized holding gain of $195.9 million. The
after-tax amount of such gain is included in the balance sheet as a
component of "Common Equity." In addition, SCI owned the following
non-voting convertible preferred shares, at the approximate cost noted:
100,000 shares series B ($75.1 million); 50,000 shares series D ($22.5
million); and 50,000 shares series E 6.5% ($75.0 million). Preferred series
B shares are convertible in March 2002 at a conversion price of $16.50 per
common share or approximately 4.5 million common shares. Preferred series D
shares are convertible in March 2002 at a conversion price of $12.75 per
common share or approximately 1.7 million common shares. Preferred series E
shares are convertible in June 2003 at a conversion price of $22.01 per
common share or approximately 3.4 million common shares. The market value
of the convertible preferred shares of Powertel is not readily
determinable. However, on an as converted basis, the market value of the
underlying common shares for the preferred shares was approximately $535
million at September 30, 1999, resulting in an unrecorded pre-tax holding
gain of $362.5 million.
<PAGE>
o ITC^ DeltaCom, Inc. (ITCD) is a fiber optic telecommunications provider.
SCI owned approximately 5.1 million common shares of ITCD. SCI's investment
in ITCD's common shares of approximately $41.2 million had a market value
of $139.0 million at September 30, 1999, resulting in a pre-tax unrealized
holding gain of $97.8 million. The after-tax amount of such gain is
included in the balance sheet as a component of "Common Equity." In
addition, SCI owned 1,480,771 shares of series A preferred stock of ITCD at
a cost of approximately $11.3 million. Series A preferred shares are
convertible in March 2002 into ITCD common shares on a two for one basis.
The market value of series A preferred stock of ITCD is not readily
determinable. However, on an as converted basis, the market value of the
underlying common stock for the series A preferred stock was approximately
$81.4 million at September 30, 1999, resulting in an unrecorded pre-tax
holding gain of $70.2 million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of cable,
television, telephone and internet services. SCI owned 71,050 units of
Knology. Each unit consists of one 11.875% Senior Discount Note due 2007
and one warrant entitling the holder to purchase .003734 shares of
preferred stock of Knology. The cost of this investment was approximately
$40 million. SCI also owned an additional 753 warrants which entitles it to
purchase 753 shares of preferred stock at $1,500 per share.
o ITC has an ownership interest in several Southeastern communications
companies. SCI owned 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 $7.1 million,
$8.9 million, and $5.0 million, respectively. Preferred series A shares are
convertible in March 2002 at a conversion price of $13.45 per common share
or approximately 2.6 million common shares. Preferred series B shares are
convertible in March 2002 at a conversion price of $43.56 per common share
or approximately 0.5 million common shares. The market value of these
investments is not readily determinable.
On July 9, 1999, ITCD completed its acquisition of AvData Systems, Inc.
(AvData). Prior to the merger, the Company held 1,577,394 common shares in
AvData at a cost of approximately $1.7 million. The Company received 49,995
common shares of ITCD valued at approximately $1.5 million as a result of the
merger. The Company's investment in ITCD had a market value of $1.4 million at
September 30, 1999, resulting in a pre-tax unrealized holding loss of $0.1
million.
Year 2000 Issue
The Year 2000 is an issue because many computers, embedded systems and
software were originally programmed using two digits rather than four digits to
identify the applicable year. This may prevent them from accurately processing
information with dates beyond 1999. Because the Year 2000 issue could have a
material impact on the operations of the Company if not addressed, the Company
has completed efforts to ensure Year 2000 readiness. This means that critical
systems, equipment, applications and business relationships have been evaluated
and should be suitable to continue into and beyond the year 2000 and that
applicable contingency plans are in place.
In 1993, the Company began the first of several projects to replace many
of its business application systems to provide increased functionality and to
improve access to business information. Accordingly, the Company has implemented
new general ledger, purchasing, materials inventory, accounts payable, and
customer information systems. These new systems, which comprise a significant
portion of the Company's applications software, were designed to be Year 2000
compliant and have been tested to confirm their Year 2000 readiness.
In 1997, the Company established a Corporate Year 2000 Project Office
(Project Office) to direct Year 2000 efforts throughout the Company. A Steering
Committee was formed to direct the efforts of the Project Office. The Steering
Committee reports to the senior officers of the Company and to the board of
directors. It is chaired by the chief financial officer of SCANA and is
comprised of officers representing all operational areas. The Project Office is
staffed by nine full time project managers and extensive support personnel. The
Project Office is responsible for addressing Year 2000 issues and coordinating
the required assessment and remediation efforts.
The Company's Year 2000 efforts encompass three projects, all reporting
to the Steering Committee. The Information Technology Project covers all
mainframe and client server application software, infrastructure hardware,
system software, desktop computers and network equipment. The Embedded Systems
Project covers all microprocessors, instruments and control devices, monitoring
equipment on power lines and in substations, security and control devices,
telephone systems and certain types of meters. The Procedures and External
Interfaces Project covers Year 2000 procedures, documentation and communications
with key suppliers, vendors, customers, financial institutions and governmental
agencies.
<PAGE>
The Company's Year 2000 project approach involved the following: (1)
inventorying all Year 2000 internal and external items and entities and updating
the Year 2000 Inventory Database; (2) performing risk analysis and corporate
prioritization of all inventory entries; (3) performing detailed assessments of
all inventory entries to determine Year 2000 readiness and establishing a
remediation action plan where necessary; (4) remediating all inventory entries
assessed as non-compliant, including repairing, replacing or developing
acceptable work-arounds; (5) testing through date simulation and comprehensive
test data; (6) implementation of all converted systems and equipment into
production operations; and (7) contingency planning.
Detailed project plans were developed for each of the Year 2000
projects. These project plans, work schedules and resource requirements were
reviewed weekly by the project managers and monthly by the Steering Committee.
The project plan tasks required to address the Company's mission critical
systems for electric, gas and other business operations and address the
Company's business relationships were successfully completed. The remaining Year
2000 project work this year is primarily focused on change management, executing
mitigation strategies to minimize potential Year 2000 risks and refining
contingency plans.
SCE&G's V. C. Summer Nuclear Station reported to the Nuclear Regulatory
Commission (NRC) at the end of June 1999 that the plant was Year 2000 ready.
Also at the end of June, SCANA reported to the North American Electric
Reliability Council (NERC) that the Company's primary systems necessary for the
generation and transmission of electricity were Year 2000 ready with two
exceptions. The first exception was associated with SCE&G's Canadys Station Unit
1 coal-fired generating plant. At the end of June, the Westinghouse Distributed
Products Family (WDPF) upgrades and Year 2000 readiness tests at two of the
three Canadys Station Units had been completed, however, the same WDPF upgrade
and Year 2000 readiness test for Unit 1 had not been completed. Canadys Station
Unit 1 generates 125 MW and represents less than 3% of SCE&G's generating
capacity. The second exception was associated with SCE&G's new Spectrum Energy
Management System (EMS). At the end of June, the Year 2000 assessment and
testing for the Spectrum System had been completed, however, the new system was
not yet on-line. In November 1999, SCE&G reported to NERC that these two
exceptions had been addressed.
The Information Technology Project Team has completed the assessment and
code remediation for all application software. These applications have been
tested in an isolated Year 2000 testing environment. The Year 2000 testing
environment will be maintained through the end of the year to test any changes
to these systems or any newly implemented applications. Independent vendor code
verifications were successfully completed for selected systems that had been
through the Company's remediation process. During the second quarter of 1999 a
comprehensive Year 2000 test was successfully performed on the Company's network
equipment. All of the Company's desktop workstations have been replaced or
upgraded to a standard configuration and software release level. All completed
assessment and remediation documentation related to mission critical
applications and technical infrastructure items has been reviewed and approved
by the Information Technology Audit Review Committee.
The Embedded Systems Project Team, which included approximately 20
engineers with prior experience with microprocessors, was formed in 1998, and
detailed assessment, remediation and testing procedures were developed. This
team worked closely with each of SCANA's business units to complete the
assessments of critical systems and equipment and any required remediation based
on the corporate prioritization process. All completed assessment and
remediation documentation related to mission critical systems or equipment
involving microprocessors has been reviewed and approved by the Embedded Systems
Audit Review Committee. Independent vendor verifications for selected embedded
system assessments were completed during the first quarter of 1999 and confirmed
the Company's previous conclusions.
The Procedures and External Interfaces Project Team has developed
written documentation and procedures for Year 2000 compliance definition,
document control, inventory, prioritization, assessment, remediation, change
control, business continuity planning, and vendor, customer and supplier
communications. This team has communicated with all significant vendors and
suppliers and assessed their Year 2000 readiness status in an attempt to
determine the extent to which the Company may be vulnerable to their failure to
remediate their own Year 2000 issues. The Company has developed communications
materials explaining its year 2000 efforts and is continuing communications with
customers and external groups, including the South Carolina and Georgia Public
Service Commissions.
<PAGE>
The Company's revised projected total cost of its Year 2000 efforts as
of September 1999 and the anticipated timing and breakdown of those expenditures
is as follows:
------------------------ -------------- ------------------ ----------------
Internal Out of Pocket Total
------------------------ -------------- ------------------ ----------------
(Millions of Dollars)
Project To Date $ 3.5 $12.0 $15.5
Remainder of 1999 0.5 0.5 1.0
------- --------- -------
Total $ 4.0 $12.5 $16.5
------------------------ -------------- ------------------ ----------------
The cost of the project is based on management's best estimates, which
are based on assumptions regarding future events. These future events include
continued availability of key resources, third parties' Year 2000 readiness and
other factors. The cost of the project is not expected to have a material impact
on the results of operations or on the financial position or cash flows of SCANA
or SCE&G. The costs of implementing the new business application systems
referred to earlier are not included in these cost estimates.
A failure to correct a material Year 2000 problem by the Company or by a
critical third party supplier could result in an interruption in, or a failure
of the Company's ability to provide energy services. At this time, the Company
believes its most reasonably likely worst case scenario is that Year 2000
failures could lead to temporary generating capacity reductions on the Company's
electrical grid, temporary intermittent interruptions in communications and
temporary intermittent interruptions in gas supply from interstate suppliers or
producers. A Year 2000 problem of this nature could result in temporary
interruptions in electric or gas service to customers. The Company has no
historical experience with interruptions caused by this scenario. However, these
temporary interruptions in service, if any, might be similar to weather-related
outages that the Company encounters from time to time in its business today.
Although the Company does not believe that this scenario will occur, the Company
is enhancing existing contingency plans to ensure preparedness and to mitigate
the long term effect of such a scenario. Since the expected impact of this
scenario on the Company's operations, cash flow and financial position cannot be
determined, there is no assurance that it would not be material.
In 1998 the Company established eight business continuity planning task
groups to develop Year 2000 business continuity plans. Contingency plans to
cover the Company's Corporate Operations, Customer Service Operations, Electric
Generation, Transmission and Distribution Operations, Gas Delivery Operations,
Telecommunications and Emergency Preparedness, Information Technology and
Procurement were developed and approved by the Company's senior management.
Detailed contingency plans that were already in place to cover weather-related
outages, computer failures and generation outages were used and/or referenced as
the basis for the Year 2000 business continuity plans. These plans include
mitigation strategies and emergency response action plans to address potential
Year 2000 scenarios, critical system failures and reliance on critical
suppliers.
NERC is coordinating the Year 2000 efforts of the electric utility
industry in the United States and contingency planning within the regional
electric reliability councils. Coordination in SCE&G's region is through the
Southeastern Electric Reliability Council (SERC). SCE&G's contingency planning
efforts are in compliance with the SERC and NERC contingency planning
guidelines, which required final contingency plans to be complete by June 30,
1999.
On September 8 and 9, 1999, the Company participated in the last of two
NERC required contingency planning drills that were intended to test backup
communications systems and the Company's ability to operate the electric grid
with manually read data instead of computerized systems. The Company's gas
transmission and distribution operations areas also participated in the drills.
The September drill also served as a full dress rehearsal for December 31, 1999.
The Company employees who participated in the September drill are the same
employees who will be on duty for December 31, 1999. During the drill, Company
employees monitored company systems for potential problems related to the date
September 9, 1999. The drills were successful and no problems were encountered
as a result of the September 9, 1999 date.
In addition to NERC and SERC, SCE&G is working with the Electric Power
Research Institute (EPRI) to address the issue of overall grid reliability and
protection. To ensure that all Year 2000 issues at its Summer Station nuclear
plant are addressed, SCE&G is closely cooperating with other utility companies
that own nuclear power plants. SCE&G and other utilities participating in
workshops sponsored by NERC and EPRI continue to share Year 2000 project
information.
<PAGE>
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1999
AS COMPARED TO THE CORRESPONDING PERIODS IN 1998
Earnings and Dividends
Net income for the three and nine months ended September 30, 1999 decreased
approximately $18.6 million and $64.1 million, respectively, when compared to
the corresponding periods in 1998. These decreases were primarily due to losses
from the Company's entry into the Georgia retail gas market, the impact of a
rate reduction at SCE&G, and milder weather. These decreases offset a one-time
gain of approximately $5.2 million from the July 1999 sale of 28 towers owned by
SCANA Communications, Inc. In addition, net income for the nine months ended
September 30, 1998 includes a one-time, after-tax reduction to depreciation
expense of approximately $5.5 million related to a change in depreciation rates
retroactive to February 1996. This change in depreciation rates resulted from
the reversal of a $257 million shift of depreciation reserves from electric
transmission and distribution assets to nuclear production assets, previously
approved in a PSC rate order in January 1996.
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 3% and 4% of
income before income taxes for the nine months ended September 30, 1999 and
1998, respectively.
The Company's Board of Directors declared the following quarterly
dividends on common stock:
- ------------------------------ --------------- -------------------------------
Declaration Dividend Record Payment
Date Per Share Date Date
- --------------------- --------------- ----------------------------------------
February 17, 1999 38 1/2 cents March 9, 1999 April 1, 1999
April 22, 1999 38 1/2 cents June 9, 1999 July 1, 1999
August 18, 1999 27 1/2 cents September 10, 1999 October 1, 1999
October 19, 1999 27 1/2 cents December 10, 1999 January 1, 2000
- ---------------------- --------------- ---------------------------------------
On February 17, 1999, the Board of Directors adopted a new common stock
dividend policy to bring the Company's dividend payout ratio more in line with
that of growth-oriented utilities. The board's action makes the Company's
indicated annual dividend rate on common stock $1.10 per share.
Electric Operations
Changes in the electric operations sales margins (including transactions
with affiliates) for the three and nine months ended September 30, 1999, when
compared to the corresponding periods in 1998, were as follows:
- ---------------------------------- -------------------------------------------
Three Months Nine Months
(Millions of Dollars) Change % Change Change % Change
- ---------------------------------- ----------- -------------------------------
Electric operating revenue - - (9.6) (1.0%)
Less: Fuel used in generation 2.9 3.4% 8.6 4.0%
Purchased power 5.6 64.5% 6.6 29.9%
- ---------------------------------- ----------- ------------------------------
Margin (8.5) (2.8%) (24.8) (3.4%)
================================== =========== ==============================
Electric operations sales margins decreased for the three and nine
months ended September 30, 1999, when compared to the corresponding periods in
1998, primarily as a result of milder weather in each of the three quarters to
date in 1999 and implementation in January 1999 of a $22.7 million annual rate
reduction ordered by the PSC. See LIQUIDITY AND CAPITAL RESOURCES.
<PAGE>
Gas Distribution
Changes in the gas distribution sales margins for the three and nine
months ended September 30, 1999, when compared to the corresponding periods in
1998, were as follows:
- --------------------------------------------------------------------------------
Three Months Nine Months
(Millions of Dollars) Change % Change Change % Change
- --------------------------------------------------------------------------------
Gas distribution operating revenue 0.4 1.1% (1.1) (0.7%)
Less: Gas purchased for resale 1.3 5.3% 0.9 0.9%
- --------------------------------------------------------------------------------
Margin (0.9) (7.7%)) (2.0) (3.1%)
================================================================================
Gas distribution sales margins for the three and nine months ended
September 30, 1999 decreased from 1998 levels primarily as a result of milder
weather.
Gas Transmission
Changes in the gas transmission sales margins (including transactions
with affiliates) for the three and nine months ended September 30, 1999, when
compared to the corresponding periods in 1998, were as follows:
- --------------------------------------------------------------------------------
Three Months Nine Months
(Millions of Dollars) Change % Change Change % Change
- --------------------------------------------------------------------------------
Gas transmission operating revenue 7.7 10.4% (4.9) (2.0%)
Less: Gas purchased for resale 9.8 16.7% 0.4 0.2%
- --------------------------------------------------------------------------------
Margin (2.1) (14.8%) (5.3) (13.0%)
================================================================================
Gas transmission sales margins for the three and nine months ended
September 30, 1999 decreased from 1998 levels primarily as a result of increased
competitiveness of alternate fuels.
Energy Marketing
Changes in the energy marketing sales margins, operating and other
expenses, and net losses for the three and nine months ended September 30, 1999,
when compared to the corresponding periods in 1998, were as follows:
- -------------------------------------------------------------------------------
Three Months Nine Months
(Millions of Dollars) Change % Change Change % Change
- -------------------------------------------------------------------------------
Gas and electric sales revenue (97.1) (0.6%) (133.9) (0.3%)
Less: Gas and electricity purchased
for resale (91.9) (0.5%) (129.6) (0.3%)
- -------------------------------------------------------------------------------
Margin (5.2) (5.8%) (4.3) (4.2%)
Less: Operating and other expenses 5.8 * 28.8 *
- -------------------------------------------------------------------------------
Net losses (11.0) * (33.1) *
===============================================================================
* Greater than 100%
Energy marketing sales margins for the three and nine months ended
September 30, 1999 decreased primarily as a result of negative margins in the
Georgia retail natural gas market. Operating and other expenses and net losses
increased primarily as a result of expenses related to the entry into the
Georgia market. See LIQUIDITY AND CAPITAL RESOURCES.
Other Operating Expenses
Changes in other operating expenses, including taxes, for the three and
nine months ended September 30, 1999, when compared to the corresponding periods
in 1998, were as follows:
- --------------------------------------------------------------------------------
Three Months Nine Months
(Millions of Dollars) Change % Change Change % Change
- --------------------------------------------------------------------------------
Other operation and maintenance 4.5 5.2% 3.0 1.2%
Depreciation and amortization 3.3 8.5% 18.6 17.4%
Income taxes (7.7) (14.1%) (21.7) (18.5%)
Other taxes (0.1) (0.2%) 1.0 1.3%
- --------------------------------------------------------------------------------
Total - - 0.9 0.2%
================================================================================
<PAGE>
Other operation and maintenance expenses for the three months ended
September 30, 1999 increased from 1998 levels primarily as a result of increased
maintenance costs for electric generation and distribution facilities. The
increase in depreciation and amortization expenses for the three and nine months
ended September 30, 1999 is due primarily to the completion of the new customer
information system in January 1999. In addition, depreciation expense for the
nine months ended September 30, 1998 reflects the non-recurring adjustment to
depreciation expense discussed under "Earnings and Dividends." The changes in
income taxes primarily reflect the changes in operating income. The changes in
other tax expense for the periods were not significant.
Other Income
Other income, net of income taxes, for the three and nine months ended
September 30, 1999 decreased approximately $2.0 million and $14.6 million,
respectively, when compared to the corresponding periods of 1998. This decrease
was primarily attributable to losses from energy marketing activities as a
result of the entry into new markets, which more than offset the earnings on
pension assets and also the gain from the sale of towers discussed under
"Earnings and Dividends."
Interest Expense
Interest expense, excluding the debt component of AFC, for the three and
nine months ended September 30, 1999 increased approximately $2.1 million and
$11.4 million, respectively, when compared to the corresponding periods in 1998.
The increase was primarily due to the issuance of medium term notes in the third
quarter of 1998 and the issuance of First Mortgage Bonds in the first quarter of
1999 and increased borrowings of short-term debt.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations, the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
<TABLE>
<CAPTION>
September 30, 1999
Expected Maturity Date
------------------------------------------------- ------------------
(Millions of Dollars)
There- Fair
Liabilities 1999 2000 2001 2002 2003 After Total Value
------- ------------------------------------------------ -----------
Long-Term Debt
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Fixed Rate ($) 106.7 363.5 27.5 27.5 284.4 1,264.2 2,073.8 2,119.1
Average Interest Rate 6.86 5.77 6.86 6.86 6.29 7.36 6.89
</TABLE>
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.
On March 9, SCE&G issued $100 million of First Mortgage Bonds having an
annual interest rate of 6 1/8 % and maturing on March 1, 2009.
On June 29, 1999 the Company issued $150 million one-year floating rate
medium term notes maturing on July 14, 2000.
In addition, the Company has invested in a telecommunications company
approximately $40 million for 11.875% senior discount notes due 2007. The fair
value of these notes approximates their carrying value. An increase in market
interest rates would result in a decrease in fair value of these notes and a
corresponding adjustment, net of tax, to other comprehensive income.
Equity price risk - Investments in telecommunications companies' marketable
equity securities are carried at their market value of $661.4 million. A ten
percent decline in market value would result in a $66.1 million reduction in
fair value and a corresponding adjustment, net of tax effect, to the related
equity account for unrealized gains/losses, a component of other comprehensive
income.
<PAGE>
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
<PAGE>
Item 1. Financial Statements
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
As of September 30, 1999 and December 31, 1998
(Unaudited)
September 30, December 31,
- -------------------------------------------------------------------------------
1999 1998
- -------------------------------------------------------------------------------
Assets (Millions of Dollars)
Utility Plant:
Electric $4,192 $4,133
Gas 375 366
Other 180 175
- -------------------------------------------------------------------------------
Total 4,747 4,674
Less accumulated depreciation and amortization 1,615 1,517
- -------------------------------------------------------------------------------
Total 3,132 3,157
Construction work in progress 295 219
Nuclear fuel, net of accumulated amortization 48 56
- -------------------------------------------------------------------------------
Utility Plant, Net 3,475 3,432
- -------------------------------------------------------------------------------
Nonutility Property and Investments, net of
accumulated depreciation 19 16
- -------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments 38 36
Receivables 195 178
Inventories (at average cost):
Fuel 26 32
Materials and supplies 48 47
Prepayments 13 8
Deferred income taxes 21 21
- -------------------------------------------------------------------------------
Total Current Assets 341 322
- -------------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 25 22
Nuclear plant decommissioning fund 62 56
Pension asset, net 136 115
Other regulatory assets 177 186
Other 82 66
- -------------------------------------------------------------------------------
Total Deferred Debits 513 476
- -------------------------------------------------------------------------------
Total $4,348 $4,246
===============================================================================
<PAGE>
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
As of September 30, 1999 and December 31, 1998
(Unaudited)
September 30, December 31,
- --------------------------------------------------------------------------------
1999 1998
- --------------------------------------------------------------------------------
Capitalization And Liabilities (Millions of Dollars)
Stockholders' Investment:
Common equity $1,558 $1,499
Preferred stock (not subject to purchase or
sinking funds) 106 106
- --------------------------------------------------------------------------------
Total Stockholders' Investment 1,664 1,605
Preferred Stock, net (subject to purchase or
sinking funds) 11 11
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 1,214 1,206
- --------------------------------------------------------------------------------
Total Capitalization 2,939 2,872
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 80 125
Current portion of long-term debt 123 29
Accounts payable 60 97
Accounts payable - affiliated companies 21 23
Customer deposits 16 17
Taxes accrued 103 75
Interest accrued 25 21
Dividends declared 27 38
Other 11 10
- --------------------------------------------------------------------------------
Total Current Liabilities 466 435
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes 554 549
Deferred investment tax credits 96 100
Reserve for nuclear plant decommissioning 62 56
Postretirement benefits 95 87
Regulatory liabilities 70 65
Other 66 82
- --------------------------------------------------------------------------------
Total Deferred Credits 943 939
- --------------------------------------------------------------------------------
Total $4,348 $4,246
================================================================================
See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Periods Ended September 30, 1999 and 1998
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
- ----------------------------------------------------------------- ------------ ----------- ------------
1999 1998 1999 1998
- ----------------------------------------------------------------- ------------ ----------- ------------
(Million of Dollars, Except Per Share Amounts)
Operating Revenues:
<S> <C> <C> <C> <C>
Electric $393 $393 $ 953 $ 962
Gas 38 37 168 169
Transit - - 1 1
- ----------------------------------------------------------------- ------------ ----------- ------------
Total Operating Revenues 431 430 1,122 1,132
- ----------------------------------------------------------------- ------------ ----------- ------------
Operating Expenses:
Fuel used in electric generation 69 68 168 164
Purchased power (including affiliated purchases) 41 33 107 95
Gas purchased from affiliate for resale 27 25 105 104
Other operation 62 61 173 173
Maintenance 23 20 60 58
Depreciation and amortization 39 35 115 96
Income taxes 45 52 90 110
Other taxes 24 24 72 71
- ----------------------------------------------------------------- ------------ ----------- ------------
Total Operating Expenses 330 318 890 871
- ----------------------------------------------------------------- ------------ ----------- ------------
Operating Income 101 112 232 261
- ----------------------------------------------------------------- ------------ -----------------------
Other Income:
Allowance for equity funds used during
construction - 2 2 5
Other income (loss) 2 (1) 6 (1)
- ---------------------------------------------------------------- ------------ ----------- ------------
Total Other Income 2 1 8 4
- ----------------------------------------------------------------- ------------ ----------- ------------
Income Before Interest Charges 103 113 240 265
- ----------------------------------------------------------------- ------------ ----------- ------------
Interest Charges (Credits):
Interest expense on long-term debt 24 24 72 72
Other interest expense 2 1 7 4
Allowance for borrowed funds used during
construction (1) (1) (3) (5)
- --------------------------------------------------------------- ------------ ----------- ------------
Total Interest Charges, Net 25 24 76 71
- ----------------------------------------------------------------- ------------ ----------- ------------
Income Before Preferred Dividend Requirements
On Mandatorily Redeemable Preferred Securities 78 89 164 194
Preferred Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 1 3 3
- ----------------------------------------------------------------- ------------ ----------- ------------
Net Income 77 88 161 191
Preferred Stock Cash Dividends (At stated rates) 2 2 5 5
- ----------------------------------------------------------------- ------------ ----------- ------------
Earnings Available for Common Stock 75 86 156 186
Retained Earnings at Beginning of Period 500 464 491 438
Common Stock Cash Dividends Declared (25) (57)
(97) (131)
================================================================= ============ =========== ============
Retained Earnings at End of Period $550 $493 $550 $ 493
================================================================= ============ =========== ============
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Periods Ended September 30, 1999 and 1998
(Unaudited)
Nine Months Ended
September 30,
- --------------------------------------------------------------------------------
1999 1998
- --------------------------------------------------------------------------------
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $161 $191
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 115 96
Amortization of nuclear fuel 13 15
Deferred income taxes, net 8 15
Pension asset (21) (18)
Post retirement benefits 8 22
Other regulatory assets 9 (7)
Regulatory liabilities 5 4
Allowance for funds used during construction (5) (10)
Over (under) collections, fuel adjustment clause (8) (1)
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (17) (25)
(Increase) decrease in inventories 5 4
(Increase) decrease in prepayments (5) (2)
Increase (decrease) in accounts payable (39) (22)
Increase (decrease) in taxes accrued 28 45
Other, net (34) 6
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 223 313
- --------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction
expenditures, net of AFC (161) (147)
Other property and investments (2) 1
- --------------------------------------------------------------------------------
Net Cash Used For Investing Activities (163) (146)
- --------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 99 -
Repayments:
Preferred stock - (1)
First and refunding mortgage bonds - (20)
Other long-term debt (9) (4)
Dividend payments:
Common stock (108) (130)
Preferred stock (6) (6)
Short-term borrowings, net (45) 20
Fuel and emission allowance financings, net 11 (10)
- --------------------------------------------------------------------------------
Net Cash Provided From (Used For) Financing Activities (58) (151)
- --------------------------------------------------------------------------------
Net Decrease In Cash And Temporary Cash Investments 2 16
Cash And Temporary Cash Investments At January 1 36 6
================================================================================
Cash And Temporary Cash Investments At September 30 $ 38 $ 22
================================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (includes capitalized interest
of $3 for 1999 and $5 for 1998) $ 73 $ 78
- Income taxes 47 41
See Notes to Consolidated Financial Statements.
<PAGE>
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1999
(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, 1998. These are interim financial statements, and the amounts reported in
the Consolidated Statements of Income are not necessarily indicative of amounts
expected for the year. In the opinion of management, the information furnished
herein reflects all adjustments, all of a normal recurring nature except as
described in Note 2, which are necessary for a fair statement of the results for
the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards No. 71 (SFAS 71). The accounting standard requires
cost-based rate-regulated utilities to recognize in their financial
statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result the Company has
recorded, as of September 30, 1999, approximately $202 million and $70
million of regulatory assets and liabilities, respectively, including
amounts recorded for deferred income tax assets and liabilities of
approximately $123 million and $51 million, respectively. The electric
and gas regulatory assets (excluding deferred income tax assets) of
approximately $45 million and $33 million, respectively, are being
recovered through rates, and the Public Service Commission of South
Carolina (PSC) has approved accelerated recovery of approximately $9
million of the electric regulatory assets. 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 that a write-off would be required,
but it is not expected that cash flows or financial position would be
materially affected.
B. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the 1999 presentation.
2. RATE MATTERS
On December 11, 1998, the PSC issued an order requiring the Company to
reduce retail electric rates on a prospective basis. The PSC acted in
response to the Company reporting that it earned a 13.04 percent return
on common equity for its retail electric operations for the twelve months
ended September 30, 1998. This return on common equity exceeded the
Company's authorized return of 12 percent by 1.04 percent, or $22.7
million, primarily as a result of record heat experienced during the
summer. The order required prospective rate reductions on a per
kilowatt-hour basis, based on actual retail sales for the twelve months
ended September 30, 1998. This action will reduce future reported return
on common equity to the PSC-authorized level if the Company experiences
the same weather effect and other business results as that of the twelve
months ended September 30, 1998. On January 12, 1999, the PSC denied the
Company's motion for reconsideration and reaffirmed the Company's return
on equity of 12 percent. The rate reductions were placed into effect with
the first billing cycle of January 1999.
3. RETAINED EARNINGS
The Restated Articles of Incorporation of the Company 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, the Federal Power Act
requires the appropriation of a portion of certain earnings from
hydroelectric projects. At September 30, 1999, approximately $28.5
million of retained earnings were restricted by this requirement as to
payment of cash dividends on common stock.
<PAGE>
4. CONTINGENCIES
With respect to commitments at September 30, 1999, reference is made to
Note 10 of Notes to Consolidated Financial Statements appearing in the
Company's Annual Report on Form 10-K for the year ended December 31,
1998. Contingencies at September 30, 1999 are as follows:
A. 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 $9.7 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
Santee Cooper) with Nuclear Electric Insurance Limited (NEIL) and
American Nuclear Insurers (ANI) providing combined property and
decontamination insurance coverage of $2 billion for any losses at
Summer Station. The Company pays annual premiums and, in addition, could
be assessed a retroactive premium not to exceed five times its annual
premium in the event of property damage loss to any nuclear generating
facility covered under the NEIL program. Based on the current annual
premium, this retroactive premium assessment would not exceed $6.1
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.
B. Environmental
The Company has 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 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. The Company has also recovered portions
of its environmental liabilities through settlements with various
insurance carriers. The Company has recovered all amounts previously
deferred for its electric operations. The Company expects to recover all
deferred amounts related to its gas operations by December 2002.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $24.3 million at September 30, 1999. 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 manufactured gas plants, 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)
have 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 in 1998 at a cost of approximately $1.5 million. Phase Two includes
excavation and installation of several
<PAGE>
permanent barriers to mitigate coal tar seepage. Phase Two began in
November 1998, and is expected to cost approximately $3 million. Additionally,
the Company is continuing to support overall site development activities by
managing potentially contaminated soils removed from construction activities
nearby. On September 30, 1998 a Record of Decision was issued which sets forth
EPA's view of the extent of each PRP's responsibility for site contamination and
the level to which the site must be remediated. On January 13, 1999 the EPA
issued a Unilateral Administrative Order which directed the Company to implement
a Remedial Design and Remedial Action Plan that would accomplish the objectives
identified by the Record of Decision. The Company and the EPA are continuing to
negotiate the remedial plan.
In October 1996 the City of Charleston and the Company settled all
environmental claims the City may have had against the Company involving
the Calhoun Park area for a payment of $26 million over four years
(1996-1999) by the Company to the City. The Company is recovering the
amount of the settlement, which does not encompass site assessment and
cleanup costs, through rates in the same manner as other amounts accrued
for site assessments and cleanup as discussed above. As part of the
environmental settlement, the Company has agreed to construct an 1,100
space parking garage on the Calhoun Park site and to transfer the facility
to the City in exchange for a 20-year municipal bond backed by revenues
from the parking garage and a mortgage on the parking garage. The total
amount of the bond is not to exceed $16.9 million, the maximum expected
project cost. The parking garage is currently under construction and is
scheduled for completion in the spring of the year 2000.
o The Company owns three other decommissioned manufactured gas plant sites
which contain residues of by-product chemicals. For the site located in
Sumter, South Carolina, effective September 15, 1998, the Company entered
into a Remedial Action Plan Contract with the South Carolina Department of
Health and Environmental Control (DHEC) pursuant to which it agreed to
undertake a full site investigation and remediation under the oversight of
DHEC. Site investigation and characterization are proceeding according to
schedule. Upon selection and successful implementation of a site remedy,
DHEC will give the Company a Certificate of Completion and a covenant not
to sue. The Company is continuing to investigate the other two sites, and
is monitoring the nature and extent of residual contamination.
5. 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. 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. Assets for the period did not change
significantly.
<TABLE>
<CAPTION>
Disclosure and Reconciliation of Reportable Segments
Three Months Ended Three Months Ended
(Millions of Dollars) September 30, 1999 September 30, 1998
- --------------------------------------------------------------------------------------------
Operating External Affiliate Operating External Affiliate
Income Revenue Revenue Income Revenue Revenue
<S> <C> <C> <C> <C> <C> <C>
Electric Operations $105 $393 $63 $118 $393 $63
Gas Distribution (2) 38 - (1) 37 -
- ---------------------------------------------------------------------------------------------
Total Reportable Segments 103 $431 $63 117 $430 $63
==== === ==== ===
Elimination of Affiliates (1) (1)
Non-reportable Segments (1) (4)
- ---------------------------------------------------------------------------------------------
Consolidated Totals $101 $112
==== ====
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Nine Months Ended Nine Months Ended
(Millions of Dollars) September 30, 1999 September 30, 1998
- -----------------------------------------------------------------------------------------------
Operating External Affiliate Operating External Affiliate
Income Revenue Revenue Income Revenue Revenue
<S> <C> <C> <C> <C> <C> <C>
Electric Operations $226 $ 953 $159 $254 $ 962 $155
Gas Distribution 13 168 - 16 169 -
- --------------------------------------------------------------------- -------------------------
Total Reportable Segments 239 $1,121 $159 270 $1,131 $155
====== ==== ====== ====
Elimination of Affiliates (4) (3)
Non-reportable Segments (3) (6)
- --------------------------------------------------------------------- -------------------------
Consolidated Totals $232 $261
==== ====
</TABLE>
<PAGE>
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, 1998.
Statements included in this discussion and analysis (or elsewhere in this
quarterly report) which are not statements of historical fact are intended to
be, and are hereby identified as, "forward looking statements" for purposes of
the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements include, but are not limited to, the following: (1) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility regulatory
environment, including the pace of deregulation of retail natural gas and
electricity markets in the United States, (3) changes in the economy, (4) the
impact of competition from other energy suppliers, (5) the management of SCE&G's
operations, (6) variations in prices of natural gas and fuels used for electric
generation, (7) growth opportunities, (8) the results of financing efforts, (9)
changes in SCE&G's accounting policies, (10) weather conditions in areas served
by SCE&G, (11) inflation, (12) exposure to environmental issues and liabilities,
(13) changes in environmental regulation, (14) unsuccessful correction of any
material Year 2000 problem or, alternatively, unsuccessful implementation of a
contingency plan by SCE&G and any critical third party suppliers, and (15) 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.
MATERIAL CHANGES IN CAPITAL RESOURCES AND LIQUIDITY
SINCE DECEMBER 31, 1998
LIQUIDITY AND CAPITAL RESOURCES
On December 11, 1998, the South Carolina Public Service Commission (PSC)
issued an order requiring SCE&G to reduce retail electric rates on a prospective
basis. The PSC acted in response to SCE&G reporting that it earned a 13.04
percent return on common equity for its retail electric operations for the
twelve months ended September 30, 1998. This return on common equity exceeded
SCE&G's authorized return of 12 percent by 1.04 percent, or $22.7 million,
primarily as a result of record-breaking heat experienced during the summer. The
order required prospective rate reductions on a per kilowatt-hour basis, based
on actual retail sales for the twelve months ended September 30, 1998. This
action will reduce future reported return on common equity to the PSC-authorized
level if SCE&G experiences the same weather effect and other business results as
that of the twelve months ended September 30, 1998. On January 12, 1999, the PSC
denied SCE&G's motion for reconsideration and reaffirmed SCE&G's return on
equity of 12 percent. The rate reductions were placed into effect with the first
billing cycle of January 1999.
On September 14, 1999, the PSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan will be implemented beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery methodology wherein SCE&G will 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 could be
carried forward for possible use in the succeeding year. The accelerated capital
recovery plan will be accomplished through existing customer rates.
<PAGE>
On September 21, 1999, SCE&G announced it will build a $180 million gas
turbine generator project in Aiken County, South Carolina. The combined-cycle
turbines will burn natural gas to produce 300 megawatts of new electric
generation and then use the exhaust heat to replace coal-fired steam that powers
two existing 75 megawatt turbines at the Urquhart Generating Station. The
turbines are scheduled to be completed by June 2002.
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 remediation efforts for the dam over the past
several years as part of SCE&G's ongoing hydroelectric operating license with
FERC. Cost of the remediation project and a schedule for construction will be
determined following the expected completion of engineering and environmental
efforts in the first quarter of 2000. FERC is requiring that engineering and
construction on the dam be completed by the end of 2002.
The following table summarizes how SCE&G generated funds for its utility
property additions and construction expenditures during the nine months ended
September 30, 1999 and 1998:
- --------------------------------------------------------------------------------
Nine Months Ended
September 30,
1999 1998
- ----------------------------------------------------------------- --------------
(Millions of Dollars)
Net cash provided from operating activities $223 $313
Net cash used for financing activities (58) (151)
Cash and temporary cash investments available
at the beginning of the period 36 6
- --------------------------------------------------------------------------------
Net cash available for utility property
additions and construction expenditures $201 $168
- --------------------------------------------------------------------------------
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $161 $147
- --------------------------------------------------------------------------------
Funds used for (provided from) nonutility
property additions and investments $ (2) $ 1
================================================================================
On March 9, 1999, SCE&G issued $100 million of First Mortgage Bonds
having an annual interest rate of 6 1/8% and maturing on March 1, 2009. These
funds were used to reduce short-term debt.
SCE&G anticipates that the remainder of its 1999 cash requirements will
be met through internally generated funds and the incurrence of additional
short-term and long-term debt. The timing and amount of such financings will
depend upon market conditions and other factors. SCE&G expects that it has or
can obtain adequate sources of financing to meet its projected cash requirements
for the next twelve months and for the foreseeable future. The ratio of earnings
to fixed charges for the twelve months ended September 30, 1999 was 3.90.
Year 2000 Issue
The Year 2000 is an issue because many computers, embedded systems and
software were originally programmed using two digits rather than four digits to
identify the applicable year. This may prevent them from accurately processing
information with dates beyond 1999. Because the Year 2000 issue could have a
material impact on the operations of SCE&G if not addressed, SCE&G has completed
efforts to ensure Year 2000 readiness. This means that critical systems,
equipment, applications and business relationships have been evaluated and
should be suitable to continue into and beyond the year 2000 and that applicable
contingency plans are in place.
In 1993, SCE&G began the first of several projects to replace many of
its business application systems to provide increased functionality and to
improve access to business information. Accordingly, SCE&G has implemented new
general ledger, purchasing, materials inventory, accounts payable, and customer
information systems. These new systems, which comprise a significant portion of
SCE&G's application software, were designed to be Year 2000 compliant and have
been tested to confirm their Year 2000 readiness.
In 1997, SCANA Corporation (SCANA), SCE&G's parent company, established
a Corporate Year 2000 Project Office (Project Office) to direct Year 2000
efforts for itself and each of its subsidiaries, including SCE&G. A Steering
Committee was formed to direct the efforts of the Project Office. The Steering
Committee reports to the senior officers of SCANA and to its board of directors.
It is chaired by SCANA's chief financial officer and is comprised of officers
representing all operational areas. The Project Office is staffed by nine full
time project managers and extensive support personnel. The Project Office is
responsible for addressing Year 2000 issues and coordinating the required
assessment and remediation efforts.
<PAGE>
SCANA's Year 2000 efforts encompass three projects, all reporting to the
Steering Committee. The Information Technology Project covers all mainframe and
client server application software, infrastructure hardware, system software,
desktop computers and network equipment. The Embedded Systems Project covers all
microprocessors, instruments and control devices, monitoring equipment on power
lines and in substations, security and control devices, telephone systems and
certain types of meters. The Procedures and External Interfaces Project covers
Year 2000 procedures, documentation and communications with key suppliers,
vendors, customers, financial institutions and governmental agencies.
SCANA's Year 2000 project approach involved the following: (1)
inventorying all Year 2000 internal and external items and entities and updating
the Year 2000 Inventory Database; (2) performing risk analysis and corporate
prioritization of all inventory entries; (3) performing detailed assessments of
all inventory entries to determine Year 2000 readiness and establishing a
remediation action plan where necessary; (4) remediating all inventory entries
assessed as non-compliant, including repairing, replacing or developing
acceptable work-arounds; (5) testing through date simulation and comprehensive
test data; (6) implementation of all converted systems and equipment into
production operations; and (7) contingency planning.
Detailed project plans were developed for each of the Year 2000
projects. These project plans, work schedules and resource requirements were
reviewed weekly by the project managers and monthly by the Steering Committee.
The project plan tasks required to address SCE&G's mission critical systems for
electric, gas and other business operations and address SCE&G's business
relationships were successfully completed. The remaining Year 2000 project work
this year is primarily focused on change management, executing mitigation
strategies to minimize potential Year 2000 risks, and refining contingency
plans.
SCE&G's V. C. Summer Nuclear Station reported to the Nuclear Regulatory
Commission (NRC) at the end of June 1999 that the plant was Year 2000 ready.
Also at the end of June, SCANA reported to the North American Electric
Reliability Council (NERC) that the Company's primary systems necessary for the
generation and transmission of electricity were Year 2000 ready with two
exceptions. The first exception was associated with SCE&G's Canadys Station Unit
1 coal-fired generating plant. At the end of June, the Westinghouse Distributed
Products Family (WDPF) upgrades and Year 2000 readiness tests at two of the
three Canadys Station Units had been completed, however, the same WDPF upgrade
and Year 2000 readiness test for Unit 1 had not been completed. Canadys Station
Unit 1 generates 125 MW and represents less than 3% of SCE&G's generating
capacity. The second exception was associated with SCE&G's new Spectrum Energy
Management System (EMS). At the end of June, the Year 2000 assessment and
testing for the Spectrum System had been completed, however, the new system was
not yet on-line. In November 1999, SCE&G reported to NERC that these two
exceptions had been addressed.
The Information Technology Project Team has completed the assessment and
code remediation for all application software. These applications have been
tested in an isolated Year 2000 testing environment. The Year 2000 testing
environment will be maintained through the end of the year to test any changes
to these systems or any newly implemented applications. Independent vendor code
verifications were successfully completed for selected systems that had been
through the Company's remediation process. During the second quarter of 1999 a
comprehensive Year 2000 test was successfully performed on the Company's network
equipment. All of SCE&G's desktop workstations have been replaced or upgraded to
a standard configuration and software release level. All completed assessment
and remediation documentation related to mission critical applications and
technical infrastructure items has been reviewed and approved by the Information
Technology Audit Review Committee.
The Embedded Systems Project Team, which included approximately 20
engineers with prior experience with microprocessors, was formed in 1998, and
detailed assessment, remediation and testing procedures were developed. This
team worked closely with each of SCE&G's business units to complete the
assessments of critical systems and equipment and any required remediation based
on the corporate prioritization process. All completed assessment and
remediation documentation related to mission critical systems or equipment
involving microprocessors has been reviewed and approved by the Embedded Systems
Audit Review Committee. Independent vendor verifications for selected embedded
system assessments were completed during the first quarter of 1999 and confirmed
SCE&G's previous conclusions.
<PAGE>
The Procedures and External Interfaces Project Team has developed
written documentation and procedures for Year 2000 compliance definition,
document control, inventory, prioritization, assessment, remediation, change
control, business continuity planning, and vendor, customer and supplier
communications. This team has communicated with all significant vendors and
suppliers and assessed their Year 2000 readiness status in an attempt to
determine the extent to which SCE&G may be vulnerable to their failure to
remediate their own Year 2000 issues. SCE&G has developed communications
materials explaining its year 2000 efforts and is continuing communications with
customers and external groups, including the South Carolina and Georgia Public
Service Commissions.
SCE&G's revised projected total cost of its Year 2000 efforts as of
September 1999 and the anticipated timing and breakdown of those expenditures is
a follows:
------------------------ -------------- ------------------ ----------------
Internal Out of Pocket Total
------------------------ -------------- ------------------ ----------------
(Millions of Dollars)
Project To Date $ 3.5 $11.5 $15.0
Remainder of 1999 0.5 0.5 1.0
------- --------- -------
Total $ 4.0 $12.0 $16.0
------------------------ -------------- ------------------ ----------------
The cost of the project is based on management's best estimates, which
are based on assumptions regarding future events. These future events include
continued availability of key resources, third parties' Year 2000 readiness and
other factors. The cost of the project is not expected to have a material impact
on the results of operations or on the financial position or cash flows of
SCE&G. The costs of implementing the new business application systems referred
to earlier are not included in these cost estimates.
A failure to correct a material Year 2000 problem by SCE&G or by a
critical third party supplier could result in an interruption in, or a failure
of SCE&G's ability to provide energy services. At this time, SCE&G believes its
most reasonably likely worst case scenario is that Year 2000 failures could lead
to temporary generating capacity reductions on SCE&G's electrical grid,
temporary intermittent interruptions in communications and temporary
intermittent interruptions in gas supply from interstate suppliers or producers.
A Year 2000 problem of this nature could result in temporary interruptions in
electric or gas service to customers. SCE&G has no historical experience with
interruptions caused by this scenario. However, these temporary interruptions in
service, if any, might be similar to weather-related outages that SCE&G
encounters from time to time in its business today. Although SCE&G does not
believe that this scenario will occur, SCE&G is enhancing existing contingency
plans to ensure preparedness and to mitigate the long term effect of such a
scenario. Since the expected impact of this scenario on SCE&G's operations, cash
flow and financial position cannot be determined, there is no assurance that it
would not be material.
In 1998, SCE&G established eight business continuity planning task
groups to develop Year 2000 business continuity plans. Contingency plans to
cover SCE&G's Corporate Operations, Customer Service Operations, Electric
Generation, Transmission and Distribution Operations, Gas Delivery Operations,
Telecommunications and Emergency Preparedness, Information Technology and
Procurement were developed and approved by senior management. Detailed
contingency plans that were already in place to cover weather-related outages,
computer failures and generation outages were used and/or referenced as the
basis for the Year 2000 business continuity plans. These plans include
mitigation strategies and emergency response action plans to address potential
Year 2000 scenarios, critical system failures, and reliance on critical
suppliers.
NERC is coordinating the Year 2000 efforts of the electric utility
industry in the United States and contingency planning within the regional
electric reliability councils. Coordination in SCE&G's region is through the
Southeastern Electric Reliability Council (SERC). SCE&G's contingency planning
efforts are in compliance with the SERC and NERC contingency planning
guidelines, which required final contingency plans to be complete by June 30,
1999.
On September 8 and 9, 1999, SCE&G participated in the last of two NERC
required contingency planning drills that were intended to test backup
communications systems and SCE&G's ability to operate the electric grid with
manually read data instead of computerized systems. SCE&G's gas distribution
operations areas also participated in the drills. The September drill also
served as a full dress rehearsal for December 31, 1999. The SCE&G employees who
participated in the September drill are the same employees who will be on duty
for December 31, 1999. During the drill, SCE&G employees monitored company
systems for potential problems related to the date September 9, 1999. The drills
were successful and no problems were encountered as a result of the September 9,
1999 date.
<PAGE>
In addition to NERC and SERC, SCE&G is working with the Electric Power
Research Institute (EPRI) to address the issue of overall grid reliability and
protection. To ensure that all Year 2000 issues at its Summer Station nuclear
plant are addressed, SCE&G is closely cooperating with other utility companies
that own nuclear power plants. SCE&G and other utilities participating in
workshops sponsored by NERC and EPRI continue to share Year 2000 project
information.
<PAGE>
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1999
AS COMPARED TO THE CORRESPONDING PERIODS IN 1998
Earnings and Dividends
Net income for the three and nine months ended September 30, 1999
decreased approximately $11.0 million and $30.3 million, respectively, when
compared to the corresponding periods in 1998. The decreases were primarily due
to the impact of a rate reduction and milder weather. In addition, net income
for the nine months ended September 30, 1998 includes a one-time, after-tax
reduction to depreciation expense of approximately $5.5 million related to a
change in depreciation rates retroactive to February 1996. This change in
depreciation rates resulted from the reversal of a $257 million shift of
depreciation reserves from electric transmission and distribution assets to
nuclear production assets, previously approved in a PSC rate order in January
1996.
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 2% and 3% of
income before income taxes for the nine months ended September 30, 1999 and
1998, respectively.
SCE&G's Board of Directors authorized payment of dividends on common
stock held by SCANA, as follows:
- -------------------- ----------------- -------------------- --------------------
Declaration Dividend Quarter Payment
Date Amount Ended Date
- -------------------- ----------------- -------------------- --------------------
February 17, 1999 $35.8 million March 31, 1999 April 1, 1999
April 22, 1999 $35.8 million June 30, 1999 July 1, 1999
August 18, 1999 $25.0 million September 30, 1999 October 1, 1999
October 19, 1999 $25.8 million December 31, 1999 January 1, 2000
- -------------------- ----------------- -------------------- --------------------
Electric Operations
Changes in the electric operations sales margins (including
transactions with affiliates) for the three and nine months ended September 30,
1999, when compared to the corresponding periods in 1998, were as follows:
- -------------------------------------------------------------------------------
Three Month Ended Nine Months Ended
(Millions of Dollars) Change % Change Change % Change
- -------------------------------------------------------------------------------
Electric operating revenue - - (9.5) (1.0%)
Less: Fuel used in generation 1.2 1.8% 3.7 2.2%
Purchased power 7.7 23.0% 12.2 12.9%
- -------------------------------------------------------------------------------
Margin (8.9) (3.0%) (25.4) (3.6%)
===============================================================================
Electric operations sales margins decreased for the three and nine
months ended September 30, 1999, when compared to the corresponding periods in
1998, primarily as a result of milder weather in each of the three quarters to
date in 1999 and implementation in January 1999 of a $22.7 million annual rate
reduction ordered by the South Carolina Public Service Commission. See LIQUIDITY
AND CAPITAL RESOURCES.
Gas Distribution
Changes in the gas distribution sales margins for the three and nine
months ended September 30, 1999, when compared to the corresponding periods in
1998, were as follows:
- --------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
(Millions of Dollars) Change % Change Change % Change
- --------------------------------------------------------------------------------
Gas operating revenue 0.4 1.1% (1.1) (0.7%)
Less: Gas purchased for resale 1.3 5.3% 0.9 0.9%
- --------------------------------------------------------------------------------
Margin (0.9) (7.7%) (2.0) (3.1%)
================================================================================
Gas distribution sales margins for the three and nine months ended
September 30, 1999 decreased from the corresponding periods in 1998 primarily as
a result of milder weather.
Other Operating Expenses
Changes in other operating expenses, including taxes, for the three and
nine months ended September 30, 1999 when compared to the corresponding periods
in 1998, were as follows:
- --------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
(Millions of Dollars) Change % Change Change % Change
- --------------------------------------------------------------------------------
Other operation and maintenance 4.2 5.2% 1.6 .07%
Depreciation and amortization 3.4 9.7% 18.7 19.4%
Income taxes (7.1) (13.6%) (19.7) (18.0%)
Other taxes (0.1) (0.6%) 0.7 1.0%
- --------------------------------------------------------------------------------
Total 0.4 0.2% 1.3 0.3%
================================================================================
Other operation and maintenance expenses for the three months ended
September 30, 1999 increased from 1998 levels primarily as a result of increased
maintenance costs for electric generation and distribution facilities. The
increase in depreciation and amortization expenses for the three and nine months
ended September 30, 1999 is due primarily to the completion of the new customer
information system in January 1999. In addition, depreciation expense for the
nine months ended September 30, 1998 reflects the non-recurring adjustment to
depreciation expense discussed under "Earnings and Dividends." The changes in
income taxes primarily reflect the changes in operating income. The changes in
other taxes for the periods were not significant.
Other Income
Other income, net of income taxes, for the three and nine months ended
September 30, 1999 increased approximately $2.7 million and $6.0 million,
respectively, and is primarily due to earnings on pension assets.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations, the table presents principal cash flows and related weighted
average interest rates by expected maturity dates.
<TABLE>
<CAPTION>
September 30, 1999
Expected Maturity Date
--------- --------------- ------------------------------------------------
(Millions of Dollars)
There- Fair
Liabilities 1999 2000 2001 2002 2003 After Total Value
------- --------- --------------------------------------------------------
Long-Term Debt
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Fixed Rate ($) 29.1 188.6 22.6 22.6 124.5 1,041.6 1,429.0 1,456.4
Average Interest Rate 6.56 5.89 6.72 6.72 7.56 7.56 7.29
</TABLE>
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.
On March 9, SCE&G issued $100 million of First Mortgage Bonds having an
annual interest rate of 6 1/8% and maturing on March 1, 2009.
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
SCANA Corporation:
For information regarding legal proceedings see Note 2 "Rate Matters,"
appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and Note 5 "Contingencies" of Notes to
Consolidated Financial Statements appearing in this Quarterly Report on
Form 10-Q.
South Carolina Electric & Gas Company:
For information regarding legal proceeding see Note 2 "Rate Matters, "
appearing in South Carolina Electric & Gas Company's Annual Report on
Form 10-K for the year ended December 31, 1998, and Note 4
"Contingencies" of Notes to Consolidated Financial Statements appearing
in this Quarterly Report on Form 10-Q.
Item 2, 3, and 5 are not applicable
Item 4. Submission of Matters to a Vote of Security-Holders (not applicable
for South Carolina Electric & Gas Company)
For information regarding submission of matters to a vote of
security-holders, see Item 4 of Part II Other Information
appearing in the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999.
Item 6. Exhibits and Reports on Form 8-K
SCANA Corporation and South Carolina Electric & Gas Company:
A. Exhibits
Exhibits filed with this Quarterly Report on Form 10-Q are
listed in the following Exhibit Index. Certain of such exhibits
which have heretofore been filed with the Securities and
Exchange Commission and which are designated by reference to
their exhibit numbers in prior filings are hereby incorporated
herein by reference and made a part hereof.
B. Reports on Form 8-K during the third quarter 1999 were as follows:
None
<PAGE>
SCANA CORPORATION
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SCANA CORPORATION
(Registrant)
November 12, 1999 By: s/K. B. Marsh
-----------------------------------------
K. B. Marsh, Senior Vice President-Finance,
Chief Financial Officer and Controller
(Principal financial and accounting officer)
<PAGE>
SOUTH CAROLINA ELECTRIC & GAS COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
(Registrant)
November 12, 1999 By: s/Jimmy E. Addison
Jimmy E. Addison
Vice President and Controller
(Principal accounting officer)
<PAGE>
EXHIBIT INDEX
Applicable to
Form 10-Q of
Exhibit
No. SCANA SCE&G 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)
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
December 15, 1993 (Filed as Exhibit 3.01 to Registration
Statement No. 333-86387)
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 Amendment of SCE&G, dated June 7, 1994 filed June
9, 1994 (Filed as Exhibit 3.02 to Registration Statement No.
333-86387)
3.05 X Articles of Amendment of SCE&G, dated November 9, 1994 (Filed
as Exhibit 3.03 to Registration Statement No. 333-86387)
3.06 X Articles of Amendment of SCE&G, dated December 9, 1994 (Filed
as Exhibit 3.04 to Registration Statement No. 333-86387)
3.07 X Articles of Correction of SCE&G, dated January 17, 1995 (Filed
as Exhibit 3.05 to Registration Statement No. 333-86387)
3.08 X Articles of Amendment of SCE&G, dated January 13, 1995 and
filed January 17, 1995 (Filed as Exhibit 3.06 to Registration
Statement No. 333-86387)
3.09 X Articles of Amendment of SCE&G, dated March 30, 1995 (Filed as
Exhibit 3.07 to Registration Statement No. 333-86387)
3.10 X Articles of Correction of SCE&G - Amendment to Statement filed
March 31, 1995, dated December 13, 1995 (Filed as Exhibit 3.08
to Registration Statement No. 333-86387)
3.11 X Articles of Amendment of SCE&G, dated December 13, 1995 (Filed
as Exhibit 3.09 to Registration Statement No. 333-86387)
3.12 X Articles of Amendment of SCE&G, dated February 18, 1997 (Filed
as Exhibit 3-L to Registration Statement No. 333-24919)
3.13 X Articles of Amendment of SCE&G, dated February 21, 1997 (Filed
as Exhibit 3.11 to Registration Statement No. 333-86387)
3.14 X Articles of Amendment of SCE&G, dated April 22, 1997 (Filed as
Exhibit 3.12 to Registration Statement No. 333-86387)
3.15 X Articles of Amendment of SCE&G, dated April 9, 1998 (Filed as
Exhibit 3.13 to Registration Statement No. 333-86387)
3.16 X By-Laws of SCANA as revised and amended on December 17, 1997
(Filed as Exhibit 4.01(b) to Registration Statement No.
333-86803)
<PAGE>
Applicable to
Form 10-Q of
Exhibit
No. SCANA SCE&G Description
3.17 X By-Laws of SCE&G as amended and adopted on December 17, 1997
(Filed as Exhibit 3.14 to Registration Statement No.333-86387)
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 to The Bank of New
York, Trustee (Filed as Exhibit 4-A to Registration Statement
No. 33-32107)
4.03 X X Indenture dated as of January 1, 1945, from the South Carolina
Power Company (the "Power Company") to Central Hanover Bank
and Trust Company, as Trustee, as supplemented by three
Supplemental Indentures dated respectively as of May 1, 1946,
May 1, 1947 and July 1, 1949(Filed as Exhibit 2-B to
Registration Statement No. 2-26459)
4.04 X X Fourth Supplemental Indenture dated as of April 1, 1950, to
Indenture referred to in Exhibit 4.03, pursuant to which SCE&G
assumed said Indenture (Filed as Exhibit 2-C to Registration
Statement No. 2-26459)
4.05 X X Fifth through Fifty-third Supplemental 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
<PAGE>
Applicable to
Form 10-Q of
Exhibit
No. SCANA SCE&G Description
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
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 4.07 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 4.07 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-G to
SCE&G Form 10-K for the year ended December 31, 1997)
4.10 X X Certificate of Trust for SCE&G Trust I (Filed as Exhibit 4-H
to SCE&G Form 10-K for the year ended December 31, 1997)
4.11 X X Junior Subordinated Indenture for SCE&G Trust I (Filed as
Exhibit 4-I to SCE&G Form 10-K for the year ended December 31,
1997)
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as Exhibit 4-J to
SCE&G Form 10-K for the year ended December 31, 1997)
<PAGE>
Applicable to
Form 10-Q of
Exhibit
No. SCANA SCE&G Description
4.13 X X Amended and Restated Trust Agreement for SCE&G Trust I
(Filed as Exhibit 4-K to SCE&G Form 10-K for the year
ended December 31, 1997)
10.01 X SCANA Voluntary Deferral Plan as amended through
October 21, 1997 (Filed as Exhibit10.01(a) to
Registration Statement No. 333-86803)
10.02 X X Supplemental Executive Retirement Plan (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-B to SCANA Form 10-K for the year ended
December 31, 1997)
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 as amended and restated effective
October 21, 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 10.01(e)
to Registration Statement No. 333-86803)
10.07 X SCANA Key Employee Retention Plan as amended
and restated effective as of October 21, 1997
(Filed as Exhibit 10-E to SCANA Form 10-K for
the year ended December 31, 1997)
10.08 X Description of SCANA Whole Life Option (Filed as
Exhibit 10-F to SCANA Form 10-K for the year ended
December 31, 1991, under cover of Form SE, File No.
1-8809)
10.09 X Description of SCANA Corporation Annual Incentive Plan
(Filed as Exhibit 10-G to SCANA Form 10-K for the year
ended December 31, 1991, under cover of Form SE, File
No. 1-8809)
27.01 X Financial Data Schedule (Filed herewith)
27.02 X Financial Data Schedule (Filed herewith)
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
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