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 March 31, 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 April 30, 1999
SCANA Corporation Without Par Value 103,572,623
South Carolina Electric Par Value $4.50 Per Share 40,296,147 1
& 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 is provided solely by SCANA Corporation and
shall be deemed not included in the Form 10-Q of South Carolina Electric & Gas
Company.
INDEX
Page
PART 1. FINANCIAL INFORMATION
SCANA Corporation Financial Section..................................... 3
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 1999 and
December 31, 1998 ........................................... 4
Consolidated Statements of Income and Retained Earnings for
the Periods Ended March 31, 1999 and 1998.................... 6
Consolidated Statements of Cash Flows for the Periods Ended
March 31, 1999 and 1998...................................... 7
Notes to Consolidated Financial Statements..................... 8
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 13
Item 3. Quantitative and Qualitative Disclosure About Market Risk...... 21
South Carolina Electric & Gas Company Financial Section................. 22
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 1999 and
December 31, 1998 ........................................... 23
Consolidated Statements of Income and Retained Earnings for
the Periods Ended March 31, 1999 and 1998.................... 25
Consolidated Statements of Cash Flows for the Periods Ended
March 31, 1999 and 1998...................................... 26
Notes to Consolidated Financial Statements..................... 27
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................... 30
Item 3. Quantitative and Qualitative Disclosure About Market Risk...... 35
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.......................................... 36
Item 6. Exhibits and Reports on Form 8-K........................... 36
Signatures.......................................................... 37
Exhibit Index....................................................... 39
2
SCANA CORPORATION
FINANCIAL SECTION
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
SCANA CORPORATION
CONSOLIDATED BALANCE SHEETS
As of March 31, 1999 and December 31, 1998
March 31, December 31,
- ----------------------------------------------------------------------------- ------ ---------
1999 1998
- ---------------------------------------------------------------------------- ------ ----------
ASSETS (Millions of Dollars)
Utility Plant:
Electric $4,408 $4,406
Gas 604 604
Other 175 175
- ----------------------------------------------------------------------------- ----------------
Total 5,187 5,185
Less accumulated depreciation and amortization 1,765 1,728
- ----------------------------------------------------------------------------- ----------------
Total 3,422 3,457
Construction work in progress 296 251
Nuclear fuel, net of accumulated amortization 56 56
Acquisition adjustment-gas, net of accumulated amortization 23 23
- ----------------------------------------------------------------------------- ----------------
Utility Plant, Net 3,797 3,787
- ----------------------------------------------------------------------------- ----------------
Nonutility Property and Investments (net of accumulated
depreciation) 531 493
- ----------------------------------------------------------------------------- ----------------
Current Assets:
Cash and temporary cash investments 71 62
Receivables 265 276
Inventories (at average cost):
Fuel 69 63
Materials and supplies 60 56
Prepayments 28 22
Deferred income taxes 20 22
- ----------------------------------------------------------------------------- ------- --------
Total Current Assets 513 501
- ----------------------------------------------------------------------------- ----------------
Deferred Debits:
Emission allowances 31 31
Environmental 22 22
Nuclear plant decommissioning fund 58 56
Pension asset, net 121 115
Other 270 276
- ----------------------------------------------------------------------------- ----------------
Total Deferred Debits 502 500
- ----------------------------------------------------------------------------- ----------------
Total $5,343 $5,281
============================================================================= ================
4
SCANA CORPORATION
CONSOLIDATED BALANCE SHEETS
As of March 31, 1999 and December 31, 1998
(Unaudited)
March 31, December 31,
- ------------------------------------------------------------------------------- --------------------
1999 1998
- ------------------------------------------------------------------------------- --------------------
CAPITALIZATION AND LIABILITIES
(Millions of Dollars)
Stockholders' Investment:
Common Equity $1,762 $1,746
Preferred stock (not subject to purchase or sinking funds) 106 106
- ---------------------------------------------------------------------------------- -----------------
Total Stockholders' Investment 1,868 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 1,736 1,623
- ---------------------------------------------------------------------------------- -----------------
Total Capitalization 3,665 3,536
- ---------------------------------------------------------------------------------- -----------------
Current Liabilities:
Short-term borrowings 174 195
Current portion of long-term debt 107 107
Accounts payable 196 219
Customer deposits 18 18
Taxes accrued 12 72
Interest accrued 39 28
Dividends declared 42 42
Other 14 13
- ---------------------------------------------------------------------------------- -----------------
Total Current Liabilities 602 694
- ---------------------------------------------------------------------------------- -----------------
Deferred Credits:
Deferred income taxes 661 628
Deferred investment tax credits 106 108
Reserve for nuclear plant decommissioning 58 56
Postretirement benefits 90 87
Other 161 172
- ---------------------------------------------------------------------------------- -----------------
Total Deferred Credits 1,076 1,051
- ---------------------------------------------------------------------------------- -----------------
Total $5,343 $5,281
================================================================================== =================
See Notes to Consolidated Financial Statements.
5
SCANA CORPORATION
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Periods Ended March 31, 1999 and 1998
(Unaudited)
Three Months Ended
March 31,
- -------------------------------------------------------------------------------- -------------
1999 1998
- -------------------------------------------------------------------------------- -------------
(Millions of Dollars
Except Per Share Amounts)
OPERATING REVENUES:
Electric $ 266 $ 269
Gas 130 137
Transit 1 -
- -------------------------------------------------------------------------------- -------------
Total Operating Revenues 397 406
- -------------------------------------------------------------------------------- -------------
Operating Expenses:
Fuel used in electric generation 61 59
Purchased power 4 2
Gas purchased for resale 81 83
Other operation 58 60
Maintenance 18 19
Depreciation and amortization 42 30
Income taxes 28 36
Other taxes 27 26
- -------------------------------------------------------------------------------- -------------
Total Operating Expenses 319 315
- -------------------------------------------------------------------------------- -------------
OPERATING INCOME 78 91
- -------------------------------------------------------------------------------- -------------
OTHER INCOME:
Allowance for equity funds used during construction 1 2
Other income (loss), net of income taxes (5) 3
- -------------------------------------------------------------------------------- -------------
Total Other Income (Loss) (4) 5
- -------------------------------------------------------------------------------- -------------
INCOME BEFORE INTEREST CHARGES AND PREFERRED STOCK DIVIDENDS 74 96
- -------------------------------------------------------------------------------- -------------
INTEREST CHARGES (CREDITS):
Interest expense on long-term debt 31 29
Other interest expense 4 2
Allowance for borrowed funds used during construction (1) (2)
- -------------------------------------------------------------------------------- -------------
Total Interest Charges, Net 34 29
- -------------------------------------------------------------------------------- -------------
INCOME BEFORE PREFERRED DIVIDEND REQUIREMENTS
ON MANDATORILY REDEEMABLE PREFERRED SECURITIES 40 67
PREFERRED DIVIDEND REQUIREMENT OF SCE&G - OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES 1 1
- -------------------------------------------------------------------------------- -------------
INCOME BEFORE PREFERRED STOCK CASH DIVIDENDS OF SUBSIDIARY 39 66
PREFERRED STOCK CASH DIVIDENDS OF SUBSIDIARY (At stated rates) 2 2
- -------------------------------------------------------------------------------- -------------
NET INCOME 37 64
RETAINED EARNINGS AT BEGINNING OF PERIOD 678 617
COMMON STOCK CASH DIVIDENDS DECLARED (40) (41)
================================================================================ =============
RETAINED EARNINGS AT END OF PERIOD $ 675 $ 640
================================================================================ =============
NET INCOME $ 37 $ 64
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (MILLIONS) 103.6 107.3
EARNINGS PER WEIGHTED AVERAGE SHARE OF COMMON STOCK (BASIC AND
DILUTED) $ .36 $ .60
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $.385 $.385
================================================================================ =============
See Notes to Consolidated Financial Statements.
6
SCANA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Periods Ended March 31, 1999 and 1998
(Unaudited)
Three Months Ended
March 31,
- --------------------------------------------------------------------------------
1999 1998
- ---------------------------------------------------------------------- ---------
(Millions of Dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $37 $ 64
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 44 32
Amortization of nuclear fuel 5 5
Deferred income taxes, net 3 23
Pension asset (6) (1)
Post-retirement benefits 3 3
Allowance for funds used during construction (3) (4)
Over (under) collections, fuel adjustment clauses 9 16
Changes in certain current assets and liabilities:
(Increase) decrease in receivables 11 (10)
(Increase) decrease in inventories (10) 4
Increase (decrease) in accounts payable (23) 15
Increase (decrease) in taxes accrued (60) (34)
Other, net 11 (17)
- --------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 21 96
- --------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Utility property additions and construction expenditures,
net of AFC (50) (51)
Increase in other property and investments (13) (7)
Sale of subsidiary assets 3 -
- --------------------------------------------------------------------------------
Net Cash Used For Investing Activities (60) (58)
- --------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds:
Issuance of First Mortgage Bonds 99 -
Issuance of notes and loans - 60
Repayments:
Notes and loans - (60)
Other long-term debt (1) -
Repurchase of common stock - (3)
Dividend payments:
Common stock (40) (40)
Preferred stock of subsidiary (2) (2)
Short-term borrowings, net (21) (1)
Fuel and emission allowance financings, net 13 (2)
- --------------------------------------------------------------------------------
Net Cash Provided From (Used For) Financing Activities 48 (48)
- --------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS 9 (10)
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1 62 60
- --------------------------------------------------------------------------------
CASH AND TEMPORARY CASH INVESTMENTS AT MARCH 31 $71 $ 50
================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for - Interest (includes capitalized interest
of $1 for 1999 and $2 for 1998) $24 $ 24
- Income taxes 5 (3)
Noncash investing activities
- Unrealized gain on securities
available for sale (net of 18 31
tax)
See Notes to Consolidated Financial Statements.
7
SCANA CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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 March 31, 1999, approximately $203 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 $43 million and $27 million, respectively, are being
recovered through rates, and the Public Service Commission of South
Carolina (PSC) has approved accelerated recovery of approximately $12
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 $56 million
and $95 million for the three months ended March 31, 1999 and 1998,
respectively. 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 12.0 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 December 21, 1998, SCE&G filed a
motion for reconsideration with the PSC. On January 12, 1999, the PSC
denied SCE&G's motion for reconsideration and reaffirmed SCE&G's return
on equity of 12.0 percent. The rate reductions were placed into effect
with the first billing cycle of January 1999.
8
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, with respect to hydroelectric projects, the
Federal Power Act requires the appropriation of a portion of certain
earnings therefrom. At March 31, 1999 approximately $26.0 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 March 31, 1999, SCANA Communications, Inc. (SCI) 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 owns approximately 4.7 million common
shares of Powertel. SCI's investment in Powertel's common shares of
approximately $69.2 million had a market value of $67.1 million at
March 31, 1999, resulting in a pre-tax unrealized holding loss of $2.1
million. The after-tax amount of such loss is included in the balance
sheet as a component of "Common Equity." In addition, SCI owns 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 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 $138.5 million at March 31, 1999, resulting in an
unrecorded pre-tax holding loss of $34.1 million.
o ITC Delta^Com, Inc. (ITCD) is a fiber optic telecommunications
provider. SCI owns approximately 4.1 million common shares of ITCD.
SCI's investment in ITCD's common shares of approximately $16.2
million had a market value of $88.4 million at March 31, 1999,
resulting in a pre-tax unrealized holding gain of $72.2 million. The
after-tax amount of such gain is included in the balance sheet as a
component of "Common Equity." In addition, SCI owns 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 $64.6 million at March
31, 1999, resulting in an unrecorded pre-tax holding gain of $53.3
million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of
cable, television, telephone and internet services. SCI owns 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 owns an additional 753 warrants
which entitles it to purchase 753 shares of preferred stock at $1,500
per share.
9
o ITC has an ownership interest in several Southeastern
communications companies. SCI owns approximately 3.1 million common
shares, 645,153 series A convertible preferred shares, and 133,664
series B convertible preferred shares of ITC. These investments
cost approximately $7.1 million, $8.9 million, and $5.0 million,
respectively. Series A and series B preferred shares are
convertible in March 2002 into ITC common shares at a conversion
price of $13.45 and $43.56, respectively, on a four for one basis.
The market value of these investments is not readily determinable.
5. CONTINGENCIES:
With respect to commitments at March 31, 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 March 31, 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 $10.0 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 $2.0 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 $20.8 million at March 31, 1999. The deferral
includes the estimated costs associated with the following matters .
10
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 will include excavation and installation of several permanent
barriers to mitigate coal tar seepage. Phase Two began in November
1998, and is expected to cost approximately $2.2 million. 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 for Remedial Design
and Remedial Action directing SCE&G to design and carry out a plan of
remediation for the Calhoun Park site. The Order is temporarily stayed
pending further negotiations between SCE&G and the EPA.
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 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 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.
11
6. SEGMENT OF BUSINESS INFORMATION:
The Company's reportable segments are listed in the following table. The Company
uses operating income to measure profitability for its 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
(unaudited)
Three Months Ended Three Months Ended
March 31, 1999 March 31, 1998
- ------------ --------------------------------- ---------------------------------
Net Operating Net Operating
Income Income Income Income
(Millions of Dollars)
Electric Operations n/a $62 n/a $73
Gas Distribution n/a 14 n/a 16
Gas Transmission $ 3 4 $ 5 5
Energy Marketing (13) n/a (1) n/a
- ----------- ---------------- ---------------- ---------------- ----------------
Total Reportable Segments (10) 80 4 94
Elimination of Affiliates - (1) - (1)
Non-reportable Segments - (1) 1 (1)
Unallocated 47 - 59 (1)
- ---------------------------- ---------------- ---------------- ----------------
Consolidated Totals $37 $78 $64 $91
============================ ================ ================ ================
External Affiliate External Affiliate
Revenue Revenue Revenue Revenue
(Millions of Dollars)
Electric Operations $266 $ 68 $269 $ 67
Gas Distribution 86 - 88 -
Gas Transmission 44 49 49 49
Energy Marketing 142 - 93 -
- ----------- ---------------- ---------------- ---------------- ----------------
Total Reportable
Segments $538 $117 $499 $116
============ ================ ================ ================ ================
12
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 areas served by
the Company's utility subsidiaries, (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. Completion of the transaction is subject to the approval of the
shareholders of both companies and applicable regulatory approvals. It is
anticipated that the approval process can be completed by the end of 1999.
Georgia Retail Gas Market
SCANA Energy Marketing (Energy Marketing), a wholly-owned subsidiary of
the Company, continues to exceed projections for acquiring customers in
Georgia's natural gas market. At March 31, 1999, Energy Marketing had
approximately 236,000 customers compared to approximately 72,000 at December 31,
1998. Energy Marketing's success has resulted in expenses being significantly
higher than expected. For the three months ended March 31, 1999, Energy
Marketing incurred losses (net of taxes) of approximately $12.5 million,
including startup costs which were expensed as incurred. A substantial portion
of those costs came from a $50 per customer promotional sign-up offer, which
expired April 15, 1999. In March 1999, the Georgia legislature approved a bill
that resulted in Georgia's natural gas market being declared competitive. As a
result, customers who have not chosen a new gas supplier by August 11, 1999 will
be randomly assigned to a new supplier based on market share. At the current
rate of expansion, Energy Marketing could have approximately 600,000 customers
after the random assignment process is completed. As a result, Energy Marketing
anticipates incurring significant losses through the
13
rest of 1999. The level of future revenues and expenditures, including startup
cost, is dependent on several factors that cannot be reasonably predicted. These
factors include how rapidly Energy Marketing gains additional 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.
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, which is competing with another
similar proposed project, 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 12.0 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 December 21, 1998, SCE&G
filed a motion for reconsideration with the PSC. On January 12, 1999, the PSC
denied SCE&G's motion for reconsideration and reaffirmed SCE&G's return on
equity of 12.0 percent. The rate reductions were placed into effect with the
first billing cycle of January 1999.
The following table summarizes how the Company generated funds for
property additions and construction expenditures during the three months ended
March 31, 1999 and 1998:
Three Months Ended March 31, 1999 1998
- --------------------------------------------------------------- --------------
(Millions of Dollars)
Net cash provided from operating activities $ 21 $ 96
Net cash provided (used) for financing activities 48 (48)
Cash provided from sale of subsidiary assets 3 -
- --------------------------------------------------------------- --------------
Cash and temporary cash investments available
at the beginning of the period 62 60
=============================================================== ==============
Net cash available for property additions
and construction expenditures $134 $108
=============================================================== ==============
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $ 50 $ 51
=============================================================== ==============
Funds used for nonutility property additions $13 $ 7
=============================================================== ==============
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.
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 indebtedness. The Company anticipates incurring
short-term and long-term debt to fund the cash consideration to be paid to
shareholders related to 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 March 31, 1999 was 3.29.
14
Investments in Equity Securities
At March 31, 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 owns approximately 4.7 million common
shares of Powertel. SCI's investment in Powertel's common shares of
approximately $69.2 million had a market value of $67.1 million at
March 31, 1999, resulting in a pre-tax unrealized holding loss of $2.1
million. The after-tax amount of such loss is included in the balance
sheet as a component of "Common Equity." In addition, SCI owns 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 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 $138.5 million at March 31, 1999, resulting in an
unrecorded pre-tax holding loss of $34.1 million.
o ITC Delta^Com, Inc. (ITCD) is a fiber optic telecommunications
provider. SCI owns approximately 4.1 million common shares of ITCD.
SCI's investment in ITCD's common shares of approximately $16.2
million had a market value of $88.4 million at March 31, 1999,
resulting in a pre-tax unrealized holding gain of $72.2 million. The
after-tax amount of such gain is included in the balance sheet as a
component of "Common Equity." In addition, SCI owns 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 $64.6 million at March
31, 1999, resulting in an unrecorded pre-tax holding gain of $53.3
million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of
cable, television, telephone and internet services. SCI owns 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 owns 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 owns approximately 3.1 million common shares, 645,153
series A convertible preferred shares, and 133,664 series B
convertible preferred shares of ITC. These investments cost
approximately $7.1 million, $8.9 million, and $5.0 million,
respectively. Series A and series B preferred shares are convertible
in March 2002 into ITC common shares at a conversion price of $13.45
and $43.56, respectively, on a four for one basis. The market value of
these investments is not readily determinable.
15
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's
goal is to be Year 2000 ready. This means that before the year 2000, critical
systems, equipment, applications and business relationships will 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, SCANA 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, SCANA has implemented new
general ledger, purchasing, materials inventory and accounts payable systems,
and is currently implementing a new customer information system. The new
customer information system is being phased into production by geographical
area, and should be fully implemented in the first half of 1999. These new
systems, which comprise a significant portion of SCANA's applications software,
are designed to be Year 2000 compliant, and therefore mitigate overall Year 2000
exposure.
In 1997, SCANA 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 SCANA 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.
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 involves 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 exist for each of the Year 2000 projects. These
project plans, work schedules and resource requirements are reviewed weekly by
the project managers and monthly by the Steering Committee. The Year 2000
projects, which will address the Company's critical systems and business
relationships, are appropriately staffed and are currently on schedule to be
completed by July 1999. As reported to the North American Electric Reliability
Council (NERC) in March 1999, the Company was 100% complete with inventory
tasks, 78% complete with detailed assessment tasks and 70% complete with
remediation tasks.
The Information Technology Project Team has completed the assessment and
initial code remediation for all application software. Many of the applications
have been tested in an isolated Year 2000 testing environment and the rest are
being tested according to the project schedule. Independent vendor verifications
of remediated code for selected applications are planned for the second quarter
of 1999. The assessment of the technical infrastructure and desktop computing
environment is complete and required remediation is in process. Testing of all
network equipment is in process. An Information Technology Audit Review
Committee has been established to review all assessments for mission critical
applications and technical infrastructure items. The Information Technology
Project was approximately 65% complete through March 1999.
16
The Embedded Systems Project Team, which includes approximately 20
engineers with prior experience with microprocessors was formed and detailed
assessment, remediation and testing procedures were developed. This team is
currently working closely with each of SCANA's business units to complete the
assessments of critical systems and equipment based on the corporate
prioritization process. An Embedded Systems Audit Review Committee continues to
review all assessments for critical systems. As assessments are completed, any
required remediation efforts are evaluated and implemented. Independent vendor
verifications for selected completed assessments were completed during the first
quarter of 1999 and confirmed the Company's previous conclusions. The Embedded
Systems Project was approximately 75% complete through March 1999.
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 is coordinating communications with all significant
vendors and suppliers 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 completed an initial survey of vendors and is currently evaluating
the responses to the survey and conducting additional inquiries where necessary.
The Company is also in the process of evaluating critical third party service
providers to ascertain their Year 2000 readiness. The Company has developed
communications materials explaining its year 2000 efforts and is continuing
communications with significant customers and external groups, including the
South Carolina and Georgia Public Service Commissions. The Procedures and
External Interfaces Project was approximately 60% complete through March 1999.
The Company's projected total cost of its Year 2000 efforts and the
anticipated timing and breakdown of those expenditures is as follows:
------------------- -------------- ------------------ ----------------
Internal Out of Pocket Total
------------------- -------------- ------------------ ----------------
(Millions of Dollars)
Project To Date $ 2 $ 9 $11
1999 3 6 9
----- ------- -----
Total $ 5 $15 $20
------------------- -------------- ------------------ ----------------
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 temporarily reduced generating capacity 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.
17
The Company has established eight business continuity planning task
groups to develop Year 2000 business continuity plans. These task groups have
developed initial draft 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. 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 initial
draft Year 2000 business continuity plans. The initial draft plans are
continuing to be enhanced, and where necessary, new plans will be developed to
include mitigation strategies and emergency response action plans to address
potential Year 2000 scenarios and critical system failures. The final plans will
also include mitigation strategies to address reliance on critical suppliers.
NERC is coordinating 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
draft contingency plans to be complete by December 31, 1998 and will require
final contingency plans to be complete by June 30, 1999.
On April 9, 1999, the Company participated in the first of two NERC
required contingency planning drills that are 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 drill.
The drills were successful and no major problems with the Company's backup
procedures were found.
In addition to NERC and SERC, SCE&G is working with the Electric Power
Research Institute 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. The utilities are sharing technical nuclear plant
operating and monitoring systems information to ensure the prompt and effective
resolution of the Year 2000 issue.
18
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 1999
AS COMPARED TO THE CORRESPONDING PERIOD IN 1998
Earnings and Dividends
Net income for the three months ended March 31, 1999 decreased
approximately $27.2 million when compared to the corresponding period in 1998.
Lower electric margins, the impact of a rate reduction, and losses from the
Company's entry into the Georgia retail gas market were only partially offset by
reduced other operation and maintenance expenses. In addition, net income for
the three months ended March 31, 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 5% and 4% of
income before income taxes for the three months ended March 31, 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 7, 1999 38 1/2 cents March 9, 1999 April 1, 1999
April 22, 1999 38 1/2 cents June 9, 1999 July 1, 1999
- ------------------- ---------------- ------------------ -------------------
On February 17, 1999, the Board of Directors announced the adoption of a
new common stock dividend policy to bring the Company's dividend payout ratio
more in line with that of growth-oriented utilities. Under the new policy, the
board anticipated declaring the current dividend of $0.385 cents per share
payable July 1, 1999 and reducing the dividend to $0.275 per share, effective
with the dividend to be paid thereafter. This action would make the Company's
indicated annual dividend rate on common stock $1.10 per share.
Electric Operations
Electric operations sales margins (including transactions with
affiliates) for the three months ended March 31, 1999 and 1998 were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- ------------------------------- --------------- --------- --------- ------------
(Million of Dollars)
Electric operating revenue $334.3 $336.2 $ (1.9) (0.6%)
Less: Fuel used in generation 103.8 100.3 3.5 3.5%
Purchased power 28.1 26.3 1.8 6.8%
- ------------------------------- --------------- --------- --------- ------------
Margin $202.4 $209.6 $ (7.2) (3.4%)
=============================== =============== ========= ========= ============
The electric operations sales margin decreased for the three months
ended March 31, 1999 when compared to the corresponding period in 1998 primarily
as a result of milder weather in the first quarter of 1999 and implementation in
January 1999 of a $22.7 million annual rate reduction ordered by the PSC. See
LIQUIDITY AND CAPITAL RESOURCES.
19
Gas Distribution
Gas distribution sales margins for the three months ended March 31, 1999
and 1998, were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- ------------------------------------------------ ---------- -------------------
(Million of Dollars)
Gas distribution operating revenue $86.1 $88.2 $(2.1) (2.4%)
Less: Gas purchased for resale 49.1 48.9 0.2 0.4%
- -------------------------------------------------------------------------------
Margin $37.0 $39.3 $(2.3) (5.9%)
===============================================================================
The gas distribution sales margin for the three months ended March 31,
1999 decreased from 1998 levels primarily as a result of increased
competitiveness of alternative fuels and milder weather.
Gas Transmission
Gas transmission sales margins (including transactions with affiliates)
for the three months ended March 31, 1999 and 1998 were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- --------------------------------------------- ----------------- ---------------
(Million of Dollars)
Gas transmission operating revenue $92.8 $97.2 $(4.4) (4.5%)
Less: Gas purchased for resale 80.5 83.0 (2.5) (3.0%)
- -------------------------------------------------------------------------------
Margin $12.3 $14.2 $(1.9) (13.4%)
===============================================================================
The gas transmission sales margin for the three months ended March 31,
1999 decreased from 1998 levels primarily as a result of increased
competitiveness of alternate fuels.
Energy Marketing
Energy Marketing sales margins for the three months ended March 31, 1999
and 1998 were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- ---------------------------------------------------------------- ---------------
(Million of Dollars)
Gas and electric sales revenue $149.4 $92.5 $56.9 61.5%
Less: Gas and electricity purchased
for resale 147.8 92.2 55.6 60.3%
- --------------------------------------------------------------------------------
Margin $ 1.6 $ .3 $ 1.3 433.3%
================================================================================
The energy marketing sales margin for the three months ended March 31,
1999 increased from 1998 levels primarily as a result of positive margins
achieved in the Georgia retail natural gas market.
Other Operating Expenses
Other operating expenses, including taxes, for the three months ended
March 31, 1999 and 1998 were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- --------------------------------------------- --------------- ------------- ---
(Million of Dollars)
Other operation and maintenance $ 76.2 $ 79.2 $ (3.0) (3.8%)
Depreciation and amortization 41.8 29.9 11.9 39.8%
Income taxes 28.3 36.6 (8.3) (22.8%)
Other taxes 27.2 26.0 1.2 4.6%
- -------------------------------------------------------------------------------
Total $173.5 $171.7 $ 1.8 1.0%
===============================================================================
20
Other operation and maintenance expenses for the three months ended
March 31, 1999 decreased from 1998 levels primarily as a result of decreased
maintenance costs for electric generation and distribution facilities. The
increase in depreciation and amortization expenses for the three months ended
March 31, 1999 reflects the non-recurring adjustment to depreciation expense in
1998 discussed under "Earnings and Dividends." The change in income tax expense
primarily reflects the change in operating income. The increase in other taxes
for the periods primarily results from increases in property taxes.
Other Income
Other income, net of income taxes, for the three months ended March 31,
1999 decreased approximately $8.7 million, when compared to the corresponding
period of 1998. This decrease was primarily attributable to losses from energy
marketing activities as a result of startup costs in new markets.
Interest Expense
Interest expense, excluding the debt component of AFC, for the three
months ended March 31, 1999 increased approximately $4.4 million, when compared
to the corresponding period in 1998. The increase was primarily due to the
issuance of medium-term notes in the third quarter of 1998, the issuance of
First Mortgage Bonds in the first quarter of 1999 and increased borrowings of
short-term debt.
Item 3. Quantitative and Qualitative Disclosure About Market Risk
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations, the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
March 31, 1999
Expected Maturity Date
-------------- ------------------ ------------------------------- --------- --------------------
(Millions of Dollars)
There- Fair
Liabilities 1999 2000 2001 2002 2003 After Total Value
-------------- --------- ----------- ----------- ----------- ----------- ----------- -----------
Long-Term Debt
Fixed Rate ($) 106.5 213.5 27.5 27.5 284.4 1,265.8 1,925.3 1,969.1
Average Interest Rate 6.86 5.93 6.87 6.87 6.29 7.35 6.99
While a decrease in interest rates would increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.
In addition, the Company has invested in a telecommunications company
approximately $40 million for 11.875% senior discount notes due 2007. The fair
value of these notes approximates cost. An increase in market interest rates
would result in a decrease in fair value of these notes and a corresponding
adjustment, net of tax, to other comprehensive income.
Equity price risk - Investments in telecommunications companies' marketable
equity securities are carried at their market value of $375.1 million. A ten
percent decline in market value would result in a $37.5 million reduction in
fair value and a corresponding adjustment, net of tax effect, to the related
equity account for unrealized gains/losses, a component of other comprehensive
income.
21
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
22
Item 1. Financial Statements
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
As of March 31, 1999 and December 31, 1998
(Unaudited)
March 31, December 31,
- ----------------------------------------------------------------------- --------
1999 1998
- ----------------------------------------------------------------------- --------
ASSETS (Millions of Dollars)
Utility Plant:
Electric $4,135 $4,133
Gas 366 366
Other 175 175
- --------------------------------------------------------------------------------
Total 4,676 4,674
Less accumulated depreciation and amortization 1,552 1,517
- --------------------------------------------------------------------------------
Total 3,124 3,157
Construction work in progress 262 219
Nuclear fuel, net of accumulated amortization 56 56
- --------------------------------------------------------------------------------
Utility Plant, Net 3,442 3,432
- --------------------------------------------------------------------------------
Nonutility Property and Investments, net of accumulated
depreciation 17 16
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments 46 36
Receivables 164 178
Inventories (at average cost):
Fuel 47 32
Materials and supplies 47 47
Prepayments 11 8
Deferred income taxes 21 21
- --------------------------------------------------------------------------------
Total Current Assets 336 322
- --------------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 22 22
Nuclear plant decommissioning fund 58 56
Pension asset, net 121 115
Other 251 252
- --------------------------------------------------------------------------------
Total Deferred Debits 483 476
- --------------------------------------------------------------------------------
Total $4,278 $4,246
================================================================================
23
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
As of March 1999 and December 31, 1998
(Unaudited)
March 31, December 31,
- ------------------------------------------------------------------------------- -----------
1999 1998
- -------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
(Millions of Dollars)
Stockholders' Investment:
Common Equity $1,510 $1,499
Preferred stock (not subject to purchase or sinking funds) 106 106
- -------------------------------------------------------------------------------------------
Total Stockholders' Investment 1,616 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 1,318 1,206
- -------------------------------------------------------------------------------------------
Total Capitalization 2,995 2,872
- -------------------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings 78 125
Current portion of long-term debt 29 29
Accounts payable 81 97
Accounts payable - affiliated companies 27 23
Customer deposits 17 17
Taxes accrued 26 75
Interest accrued 25 21
Dividends declared 38 38
Other 10 10
- -------------------------------------------------------------------------------------------
Total Current Liabilities 331 435
- ------------------------------------------------------------------------------- -----------
Deferred Credits:
Deferred income taxes 570 549
Deferred investment tax credits 99 100
Reserve for nuclear plant decommissioning 58 56
Postretirement benefits 90 87
Other 135 147
- -------------------------------------------------------------------------------------------
Total Deferred Credits 952 939
- -------------------------------------------------------------------------------------------
Total $4,278 $4,246
===========================================================================================
See Notes to Consolidated Financial Statements.
24
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Periods Ended March 31, 1999 and 1998
(Unaudited)
Three Months Ended
March 31,
- --------------------------------------------------------------------------------
1999 1998
- --------------------------------------------------------------------------------
(Millions of Dollars)
OPERATING REVENUES:
Electric $266 $270
Gas 86 88
Transit 1 -
- --------------------------------------------------------------------------------
Total Operating Revenues 353 358
- --------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 45 43
Purchased power (including affiliated purchases) 28 26
Gas purchased from affiliate for resale 49 49
Other operation 53 56
Maintenance 17 18
Depreciation and amortization 38 26
Income taxes 26 33
Other taxes 25 24
- --------------------------------------------------------------------------------
Total Operating Expenses 281 275
- --------------------------------------------------------------------------------
OPERATING INCOME 72 83
- --------------------------------------------------------------------------------
OTHER INCOME:
Allowance for equity funds used during construction 1 2
Other income 1 -
- --------------------------------------------------------------------------------
Total Other Income 2 2
- --------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES 74 85
- --------------------------------------------------------------------------------
INTEREST CHARGES (CREDITS):
Interest expense on long-term debt 23 24
Other interest expense 3 2
Allowance for borrowed funds used during construction (1) (2)
- --------------------------------------------------------------------------------
Total Interest Charges, Net 25 24
- --------------------------------------------------------------------------------
INCOME BEFORE PREFERRED DIVIDEND REQUIREMENTS
ON MANDATORILY REDEEMABLE PREFERRED SECURITIES 49 61
PREFERRED DIVIDEND REQUIREMENT OF SCE&G - OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES 1 1
- --------------------------------------------------------------------------------
NET INCOME 48 60
Preferred Stock Cash Dividends (At stated rates) (2) (2)
- --------------------------------------------------------------------------------
Earnings Available for Common Stock 46 58
Retained Earnings at Beginning of Period 491 438
Common Stock Cash Dividends Declared (36) (37)
================================================================================
Retained Earnings at End of Period $501 $459
================================================================================
See Notes to Consolidated Financial Statements.
25
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Periods Ended March 31, 1999 and 1998
(Unaudited)
Three Months Ended
March 31,
- -------------------------------------------------------------------- -----------
1999 1998
- -------------------------------------------------------------------- -----------
(Millions of Dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 48 $ 60
Adjustments to reconcile net income to net
cash provided from operating activities:
Depreciation and amortization 38 26
Amortization of nuclear fuel 5 5
Deferred income taxes, net 22 20
Pension asset (7) (1)
Post retirement benefits 3 3
Allowance for funds used during construction (2) (4)
Over (under) collections, fuel adjustment clauses 9 16
Changes in certain current assets and liabilities:
(Increase) decrease in receivables 14 1
(Increase) decrease in inventories (15) (5)
Increase (decrease) in accounts payable (12) (9)
Increase (decrease) in taxes accrued (49) (15)
Other, net (22) (21)
- -------------------------------------------------------------------- -----------
Net Cash Provided From Operating Activities 32 76
- -------------------------------------------------------------------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Utility property additions and construction expenditures,
net of AFC (48) (46)
- -------------------------------------------------------------------- -----------
Net Cash Used For Investing Activities (48) (46)
- -------------------------------------------------------------------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds:
Issuance of First Mortgage Bonds 99 -
Dividend payments:
Common stock (36) (56)
Preferred stock (2) (2)
Short-term borrowings, net (48) 44
Fuel and emission allowance financings, net 13 (2)
- -------------------------------------------------------------------- -----------
Net Cash Provided From (Used For) Financing Activities 26 (16)
- -------------------------------------------------------------------- -----------
NET INCREASE IN CASH AND TEMPORARY CASH INVESTMENTS 10 14
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1 36 6
==================================================================== ===========
CASH AND TEMPORARY CASH INVESTMENTS AT MARCH 31 $ 46 $ 20
==================================================================== ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for - Interest (includes capitalized interest
of $1 for 1999 and $2 for 1998) $ 21 $ 21
- Income taxes 4 (20)
See Notes to Consolidated Financial Statements.
26
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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 March 31, 1999, approximately $195 million and $69
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 $43 million and $27 million, respectively, are being
recovered through rates, and the Public Service Commission of South
Carolina (PSC) has approved accelerated recovery of approximately $12
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 December 21, 1998, the Company filed
a motion for reconsideration with the PSC. On January 12, 1999, the PSC
denied the Company's motion for reconsideration, ruled that no further
rate action was required, 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, with respect to hydroelectric
projects, the Federal Power Act requires the appropriation of a portion
of certain earnings therefrom. At March 31, 1999, approximately $26.0
million of retained earnings were restricted by this requirement as to
payment of cash dividends on common stock.
27
4. CONTINGENCIES:
With respect to commitments at March 31, 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 March 31, 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 $2.0 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 $20.8 million at March 31, 1999. The deferral
includes the estimated costs associated with the following matters.
o In September 1992, the 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 will include excavation and installation of several
permanent barriers to mitigate coal tar seepage. Phase Two began in
November 1998, and is expected to cost approximately
28
$2.2 million. 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 for
Remedial Design and Remedial Action directing the Company to design and
carry out a plan of remediation for the Calhoun Park site. The Order is
temporarily stayed pending further negotiations between the Company and
the EPA.
In October 1996 the City of Charleston and the Company 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. 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, SCE&G 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.
Disclosure and Reconciliation of Reportable Segments
(unaudited)
Three Months Ended Three Months Ended
March 31, 1999 March 31, 1998
- --------------------------------------------------------------------- ----------
Operating External Affiliate Operating External Affiliate
Income Revenue Revenue Income Revenue Revenue
(Millions of Dollars)
Electric Operations $60 $266 $44 $69 $269 $42
Gas Distribution 14 86 - 16 88 -
- --------------------------------------------------------------------------------
Total Reportable Segments 74 $352 $44 85 $357 $42
==== === ==== ===
Elimination of Affiliates (1) (1)
Non-reportable Segments (1) (1)
- --------------------------------------------------------------------------------
Consolidated Totals $72 $83
=== ===
29
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 SCE&G's 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 SEC. 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%
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 12.0% by 1.04%, 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 December 21, 1998, SCE&G filed a
motion for reconsideration with the PSC. On January 12, 1999, the PSC denied
SCE&G's motion for reconsideration and reaffirmed SCE&G's return on equity of
12.0%. The rate reductions were placed into effect with the first billing cycle
of January 1999.
30
The following table summarizes how SCE&G generated funds for its utility
property additions and construction expenditures during the three months ended
March 31, 1999 and 1998:
Three Months Ended March 31, 1999 1998
- -----------------------------------------------------------------------------
(Millions of Dollars)
Net cash provided for operating activities $32 $76
Net cash provided from (used for) financing
activities 26 (16)
Cash and temporary cash investments available
at the beginning of the period 36 6
- ----------------------------------------------------------------------------
Net cash available for utility property additions
and construction expenditures $94 $66
============================================================================
Funds used for utility property additions and
construction expenditures, net of noncash
allowance for funds used during construction $48 $ 46
============================================================================
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 1998 cash requirements will
be met through internally generated funds and the incurrence of additional
short-term and long-term indebtedness. 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 March 31, 1999
was 4.21.
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's goal is to
be Year 2000 ready. This means that before the year 2000, critical systems,
equipment, applications and business relationships will 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 and accounts payable systems,
and is currently implementing a new customer information system. The new
customer information system is being phased into production by geographical
area, and should be fully implemented in the first half of 1999. These new
systems, which comprise a significant portion of SCE&G's application software,
are designed to be Year 2000 compliant, and therefore mitigate overall Year 2000
exposure.
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 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.
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, instrument 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.
31
SCANA's Year 2000 project approach involves 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 exist for each of the Year 2000 projects. These
project plans, work schedules and resource requirements are reviewed weekly by
the project managers and monthly by the Steering Committee. The Year 2000
projects, which will address SCE&G's critical systems and business
relationships, are appropriately staffed and are currently on schedule to be
completed by July 1999. As reported to the North American Electric Reliability
Council (NERC) in March 1999, SCE&G was 100% complete with inventory tasks, 78%
complete with detailed assessment tasks and 70% complete with remediation tasks.
The Information Technology Project Team has completed the assessment and
initial code remediation for all application software. Many of the applications
have been tested in an isolated Year 2000 testing environment and the rest
continue to be tested according to the project schedule. Independent vendor
verifications of remediated code for selected applications are planned for the
second quarter of 1999. The assessment of the technical infrastructure and
desktop computing environment is complete and required remediation is in
process. Testing of all network equipment is in process. An Information
Technology Audit Review Committee has been established to review all assessments
for mission critical applications and technical infrastructure items. The
Information Technology Project was approximately 65% complete through March
1999.
The Embedded Systems Project Team, which includes approximately 20
engineers with prior experience with microprocessors, was formed and detailed
assessment, remediation and testing procedures were developed. This team is
currently working closely with each of SCE&G's business units to complete the
assessments of critical systems and equipment based on the corporate
prioritization process. An Embedded Systems Audit Review Committee continues to
review all assessments for critical systems. As assessments are completed, any
required remediation efforts are evaluated and implemented. Independent vendor
verifications for selected completed assessments were completed during the first
quarter of 1999 and confirmed SCE&G's previous conclusions. The Embedded Systems
Project was approximately 75% complete through March 1999.
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 is coordinating communications with all significant
vendors and suppliers 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 completed an initial survey of vendors and is currently evaluating the
responses to the survey and conducting additional inquiries where necessary.
SCE&G is also in the process of evaluating critical third party service
providers to ascertain their Year 2000 readiness. The Company has developed
communications materials explaining its year 2000 efforts and is continuing
communications with significant customers and external groups, including the
South Carolina Public Service Commission. The Procedures and External Interfaces
Project was approximately 60% complete through March 1999.
SCE&G's projected total cost of its Year 2000 efforts and the
anticipated timing and breakdown of these expenditures is a follows:
- ----------------------------------------------------------------------------
Internal Out of Pocket Total
- ----------------------------------------------------------------------------
Project To Date $ 2 $ 8 $ 10
1999 3 6 9
- - -
Total $ 5 $ 14 $19
- ----------------------------------------------------------------------------
32
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 temporarily reduced generating capacity 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 our 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.
SCE&G has established eight business continuity planning task groups to
develop Year 2000 business continuity plans. These task groups have developed
initial draft 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. 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 initial draft Year 2000
business continuity plans. The initial draft plans are continuing to be
enhanced, and where necessary, new plans are being developed to include
mitigation strategies and emergency response action plans to address potential
Year 2000 scenarios and critical system failures. The final plans will also
include mitigation strategies to address reliance on critical suppliers.
NERC is coordinating 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
draft contingency plans to be complete by December 31, 1998 and will require
final contingency plans to be complete by June 30, 1999.
On April 9, 1999, SCE&G participated in the first of two NERC required
contingency planning drills that are intended to test backup communications
systems and the Company's ability to operate the electric grid with manually
read data instead of computerized systems. SCE&G's gas distribution operations
also participated in the drill. The drills were successful and no major problems
with the Company's backup procedures were found.
In addition to NERC and SERC, SCE&G is working with the Electric Power
Research Institute 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. The utilities are sharing technical nuclear plant
operating and monitoring systems information to ensure the prompt and effective
resolution of the Year 2000 issue.
33
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 1999
AS COMPARED TO THE CORRESPONDING PERIOD IN 1998
Earnings and Dividends
Net income for the three months ended March 31, 1999 decreased
approximately $11.7 million when compared to the corresponding periods in 1998.
Lower electric margins and the impact of a rate reduction were only partially
offset by reduced other operation and maintenance expenses. In addition, net
income for the three months ended March 31, 1998 include 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 three months ended March 31, 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
- -------------------- ----------------- ----------------- -----------------
Electric Operations
Electric operations sales margins (including transactions with
affiliates) for the three months ended March 31, 1999 and 1998 were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- --------------------------------------------------------------------------------
(Million of Dollars)
Electric operating revenue $309.8 $311.6 $(1.8) (0.6%)
Less: Fuel used in generation 87.3 84.0 3.3 3.9%
Purchased power 28.1 26.3 1.8 6.8%
- --------------------------------------------------------------------------------
Margin $194.4 $201.3 $(6.9) (3.4%)
================================================================================
The electric operations sales margin decreased for the three months
ended March 31, 1999 when compared to the corresponding period in 1998 primarily
as a result of milder weather in the first quarter of 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
Gas distribution sales margins for the three months ended March 31,
1999 and 1998 were as follows:
Three Months Ended March 31, 1999 1998 Change % Change
- --------------------------------------------------------------------------------
(Million of Dollars)
Gas operating revenue $86.1 $88.2 $(2.1) (2.3%)
Less: Gas purchased for resale 49.1 48.9 0.2 0.3%
- --------------------------------------------------------------------------------
Margin $37.0 $39.3 $(2.3) (5.6%)
================================================================================
34
The gas distribution sales margin for the three months ended March 31, 1999
decreased from 1998 levels primarily as a result of increased competitiveness of
alternative fuels and milder weather.
Other Operating Expenses
Changes in other operating expenses, including taxes, for the three months
ended March 31, 1999 when compared to the corresponding periods in 1998, were as
follows:
Three Months Ended March 31, 1999 1998 Change % Change
- -------------------------------------------------------------------------------
(Million of Dollars)
Other operation and maintenance $ 70.2 $ 73.9 $(3.7) (5.0%)
Depreciation and amortization 38.2 26.2 12.0 45.8%
Income taxes 26.1 33.5 (7.4) (22.1%)
Other taxes 24.6 23.5 1.1 4.7%
- -------------------------------------------------------------------------------
Margin $159.1 $157.1 $ 2.0 1.3%
===============================================================================
Other operation and maintenance expenses for the three months ended March
31, 1999 decreased from 1998 levels primarily as a result of decreased
maintenance costs for electric generation and distribution facilities. The
increase in depreciation and amortization expenses for the three months ended
March 31, 1999 reflects the non-recurring adjustment to depreciation expense
discussed under "Earnings and Dividends." The change in income tax expense
primarily reflects the change in operating income. The increase in other taxes
for the period primarily results from increases in property taxes.
Other Income
Other income, net of income taxes, for the three months ended March 31,
1999 increased approximately $0.8 million and is not material.
Item 3. Quantitative and Qualitative Disclosure About Market Risk
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations, the table presents principal cash flows and related weighted
average interest rates by expected maturity dates.
March 31, 1999
Expected Maturity Date
-------------- ------------------ ------------------------------- --------- --------------------
(Millions of Dollars)
There- Fair
Liabilities 1999 2000 2001 2002 2003 After Total Value
-------------- --------- ----------- ----------- ----------- ----------- ----------- -----------
Long-Term Debt
Fixed Rate ($) 29.1 188.6 22.6 22.6 124.5 1,043.4 1,437.1 1,456.4
Average Interest Rate 6.56 5.89 6.72 6.72 7.56 7.55 7.28
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.
35
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.
Items 2, 3, 4 and 5 are not applicable for SCANA Corporation or South Carolina
Electric & Gas Company.
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 first quarter 1999 were as follows:
SCANA filed a current report on Form 8-K:
Date of report: February 16, 1999
Items reported: Item 5 and Item 7
SCE&G filed a current report on Form 8-K:
Date of report: February 16, 1999
Items reported: Item 5 and Item 7
36
SCANA CORPORATION
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SCANA CORPORATION
(Registrant)
May 17, 1999 By: s/K. B. Marsh
-------------------
K. B. Marsh,Senior Vice President -Finance,
Chief Financial Officer and Controller
(Principal financial officer)
37
SOUTH CAROLINA ELECTRIC & GAS COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
(Registrant)
May 17, 1999 By: s/Jimmy E. Addison
Jimmy E. Addison
Vice President and Controller
(Principal accounting officer)
38
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 SCANA Form S-4 on May 11, 1999)
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-A to Form 10-Q for the quarter ended June 30,
1994, File No. 1-3375)
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-B to Form 10-Q for the
quarter ended June 30, 1994, File No. 1-3375)
3.05 X Articles of Amendment of SCE&G, dated November 9, 1994 (Filed
as Exhibit 3-C to Form 10-K for the year ended December 31,
1994, File No. 1-3375)
3.06 X Articles of Amendment of SCE&G, dated December 9, 1994 (Filed
as Exhibit 3-D to Form 10-K for the year ended December 31,
1994, File No. 1-3375)
3.07 X Articles of Correction of SCE&G, dated January 17, 1995 (Filed
as Exhibit 3-E to From 10-K for the year ended December 31,
1994, File No. 1-3375)
3.08 X Articles of Amendment of SCE&G, dated January 13, 1995 and
filed January 17, 1995 (Filed as Exhibit 3-F to Form 10-K for
the year ended December 31, 1994, File No. 1-3375)
3.09 X Articles of Amendment of SCE&G, dated March 31, 1995 (Filed as
Exhibit 3-G to Form 10-Q for the quarter ended March 31, 1995,
File No. 1-3375)
3.10 X Articles of Correction of SCE&G - Amendment to Statement filed
March 31, 1995, dated December 12, 1995 (Filed as Exhibit 3-H
to Form 10-K for the year ended December 31, 1995,
Filed No. 1-3375)
3.11 X Articles of Amendment of SCE&G, dated December 13, 1995 (Filed
as Exhibit 3-I to Form 10-K for the year ended December 31,
1995, File No. 1-3375)
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-L to Form 10-Q for the quarter ended
March 31, 1997)
3.14 X Articles of Amendment of SCE&G, dated April 22, 1997 (Filed as
Exhibit 3-M to Form 10-Q for the quarter ended June 30, 1997)
3.15 X Articles of Amendment of SCE&G, dated April 9, 1998 (Filed
herewith on page 43)
3.16 X By-Laws of SCANA as revised and amended on December 17, 1997
(Filed as Exhibit 3-C to Form 10-K for the year ended
December 31, 1997)
39
Applicable to
Form 10-Q of
Exhibit
No. SCANA SCE&G Description
3.17 X By-Laws of SCE&G as revised and amended on December 17, 1997
(Filed as Exhibit 3-J to Form 10-K for the year ended
December 31, 1997)
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-second Supplemental Indenture referred to
in Exhibit 4.03 dated as of the dates indicated below and filed
as exhibits to the Registration Statements and 1934 Act
reports 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. 2-26489
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
40
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
4.06 X X Fifty-Third Supplemental Indenture, dated May 1, 1999, to
Indenture referred to in Exhibit 4.03 (Filed herewith on page 45)
4.07 X X Indenture dated as of April 1, 1993 from South Carolina Electric
& Gas Company to NationsBank of Georgia, National Association
(Filed as Exhibit 4.07 to Registration Statement No. 33-49421)
4.08 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)
4.09 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)
4.10 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)
4.11 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)
4.12 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)
4.13 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)
41
Applicable to
Form 10-Q of
Exhibit
No. SCANA SCE&G Description
4.14 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 Exhibit 10.01 to SCANA Form 10-K for the year
ended December 31, 1998)
10.02 X X Supplemental Executive Retirement Plan (Filed as Exhibit 10-A
to SCE&G Form 10-K for the year ended December 31, 1997)
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-C to SCANA Form 10-K for the year ended December 31, 1997)
10.05 X SCANA Supplementary Key Executive Severance Benefit Plan as
amended and restated effective October 21, 1997 (Filed as
Exhibit 10.06 to SCANA Form 10-K for the year ended December
31, 1998)
10.06 X SCANA Performance Share Plan as amended and restated effective
January 1, 1998 (Filed as Exhibit 10.07 to SCANA Form 10-K for
the year ended December 31, 1998)
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)
10.9 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)
42