SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-3375
SOUTH CAROLINA ELECTRIC & GAS COMPANY
(Exact name of registrant as specified in its charter)
SOUTH CAROLINA 57-0248695
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)
1426 MAIN STREET, COLUMBIA, SOUTH CAROLINA 29201
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (803) 748-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
5% Cumulative Preferred Stock
par value $50 per share New York Stock Exchange
7.55% Trust Preferred Securities, Series A
liquidation value $25 per Trust
Preferred Security New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
Indicate by check mark whether the registrant: (1) has 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 registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes x . No .
1
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
State the aggregate market value of the voting and non-voting
common equity held by non-affiliates of the registrant. The
aggregate market value shall be computed by reference to the price
at which the common equity was sold, or the average bid and asked
prices of such common equity, as of a specified date within 60 days
prior to the date of filing. (See definition of affiliate in Rule
405.)
Note. If a determination as to whether a particular
person or entity is an affiliate cannot be made without
involving unreasonable effort and expense, the aggregate
market value of the common stock held by non-affiliates
may be calculated on the basis of assumptions reasonable
under the circumstances, provided that the assumptions
are set forth in this form.
The aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant as of February 27,
1997 was zero.
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:
Indicate by check mark whether the registrant has filed all
documents and reports required to be filed by Section 12, 13 or
15(d) of the Securities Exchange Act of 1934 subsequent to the
distribution of securities under a plan confirmed by a court.
Yes No
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest practicable
date.
As of February 27, 1998 there were issued and outstanding
40,296,147 shares of the registrant's common stock, $4.50 par
value, all of which were held, beneficially and of record, by SCANA
Corporation.
DOCUMENTS INCORPORATED BY REFERENCE.
List hereunder the following documents if incorporated by
reference and the Part of the Form 10-K (e.g., Part I, Part II,
etc.) into which the document is incorporated: (1) any annual
report to security-holders; (2) any proxy or information statement;
and (3) any prospectus filed pursuant to Rule 424(b) or (c) under
the Securities Act of 1933. The listed documents should be clearly
described for identification purposes (e.g., annual report to
security-holders for fiscal year ended December 24, 1980).
NONE
2
TABLE OF CONTENTS
Page
DEFINITIONS ....................................................... 4
PART I
Item 1. Business ............................................ 5
Item 2. Properties .......................................... 20
Item 3. Legal Proceedings ................................... 22
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 22
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters..................... 22
Item 6. Selected Financial Data ............................. 23
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ...... 24
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk......................................... 33
Item 8. Financial Statements and Supplementary Data ......... 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 60
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 60
Item 11. Executive Compensation .............................. 64
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 71
Item 13. Certain Relationships and Related Transactions ...... 71
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 71
SIGNATURES ........................................................ 72
3
DEFINITIONS
The following abbreviations used in the text have the meaning set
forth below unless the context requires otherwise:
ABBREVIATION TERM
AFC......................... Allowance for Funds Used During Construction
BTU......................... British Thermal Unit
Circuit Court............... South Carolina Circuit Court
Clean Air Act............... Clean Air Act Amendments of 1990
Company..................... South Carolina Electric & Gas Company
Consumer Advocate........... Consumer Advocate of South Carolina
Dekatherm................... One Million BTUs
DHEC........................ South Carolina Department of Health and
Environmental Control
DOE......................... United States Department of Energy
EPA......................... United States Environmental Protection Agency
FERC........................ United States Federal Energy Regulatory
Commission
Fuel Company................ South Carolina Fuel Company, Inc., an
affiliate
GENCO....................... South Carolina Generating Company, Inc., an
affiliate
KVA......................... Kilovolt-ampere
KW.......................... Kilowatt
KWH......................... Kilowatt-hour
LLC......................... Limited Liability Company
LNG......................... Liquefied Natural Gas
MCF......................... Thousand Cubic Feet
MW.......................... Megawatt
NEPA........................ National Energy Policy Act of 1992
NRC......................... United States Nuclear Regulatory Commission
Pipeline Corporation........ South Carolina Pipeline Corporation, an
affiliate
PRP......................... Potentially Responsible Party
PSA......................... The South Carolina Public Service Authority
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935,
as amended
SCANA....................... SCANA Corporation and its subsidiaries
Southern Natural............ Southern Natural Gas Company
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipeline Corporation
USEC........................ United States Enrichment Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams Coal-Fired, Electric
Generating Station Owned by GENCO
4
PART I
ITEM 1. BUSINESS
THE COMPANY
ORGANIZATION
The Company, a wholly owned subsidiary of SCANA, is a South
Carolina corporation organized in 1924 and has its principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Company had 3,774
full-time, permanent employees as of December 31, 1997 as compared
to 3,637 full-time, permanent employees as of December 31, 1996.
SCANA, a South Carolina corporation, was organized in 1984 and
is a public utility holding company within the meaning of PUHCA but
is presently exempt from registration under such Act. SCANA holds
all of the issued and outstanding common stock of the Company.
(See Note 1A of Notes to Consolidated Financial Statements.)
INDUSTRY SEGMENTS
The Company is a regulated public utility engaged in the
generation, transmission, distribution and sale of electricity and
in the purchase and sale, primarily at retail, of natural gas in
South Carolina. The Company also renders urban bus service in the
metropolitan area of Columbia, South Carolina. The Company's
business is subject to seasonal fluctuations. Generally, sales of
electricity are higher during the summer and winter months because
of air-conditioning and heating requirements, and sales of natural
gas are greater in the winter months due to its use for heating
requirements.
The Company's electric service area extends into 24 counties
covering more than 15,000 square miles in the central, southern
and southwestern portions of South Carolina. The service area for
natural gas encompasses all or part of 30 of the 46 counties in
South Carolina and covers more than 21,000 square miles. The total
population of the counties representing the Company's combined
service area is approximately 2.4 million.
The predominant industries in the territories served by the
Company include: synthetic fibers; chemicals and allied products;
fiberglass and fiberglass products; paper and wood products; metal
fabrication; stone, clay and sand mining and processing; and
various textile-related products.
Information with respect to industry segments for the years
ended December 31, 1997, 1996 and 1995 is contained in Note 11 of
Notes to Consolidated Financial Statements and all such information
is incorporated herein by reference.
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulation.
Deregulation of electric wholesale and retail markets is creating
opportunities to compete for new and existing customers and
markets. As a result, profit margins and asset values of some
utilities could be adversely affected. Legislative initiatives at
the Federal and state levels are being considered and, if enacted,
could mandate market deregulation. The pace of deregulation,
future prices of electricity, and the regulatory actions which may
be taken by the PSC and the FERC in response to the changing
environment cannot be predicted. However, the FERC, in issuing
Order 888 in April 1996, has accelerated competition among electric
utilities by providing for open access to wholesale transmission
service. Order 888 requires utilities under FERC jurisdiction that
own, control or operate transmission lines to file
nondiscriminatory open access tariffs that offer
5
to others the same transmission service they provide themselves.
The FERC has also permitted utilities to seek recovery of wholesale
stranded costs from departing customers by direct assignment.
Approximately two percent of the Company's electric revenue is
under FERC jurisdiction for the purpose of setting rates for
wholesale service. Legislation is pending in South Carolina that
would deregulate the state's retail electric market and enable
customers to choose their supplier of electricity. The Company is
not able to predict whether the legislation will be enacted and, if
it is, the conditions it will impose on utilities that currently
operate in the state and future market participants.
The Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company operates
Strategic Business Units. Maintaining a competitive cost structure
is of paramount importance in the utility's strategic plan. SCE&G
has undertaken a variety of initiatives, including reductions in
operation and maintenance costs, the accelerated recovery of
SCE&G's electric regulatory assets and the shift, for retail
ratemaking purposes only, of depreciation reserves from
transmission and distribution assets to nuclear production assets.
SCE&G has also established open access transmission tariffs and is
selling bulk power to wholesale customers at market-based rates.
Significant new customer and management information systems will be
implemented in 1998. Marketing of services to commercial and
industrial customers has been increased significantly. SCE&G has
obtained long-term power supply contracts with a significant
portion of its industrial customers. The Company believes that
these actions as well as numerous others that have been and will be
taken demonstrate its ability and commitment to succeed in the new
operating environment to come.
Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment occur,
the Company may no longer be eligible to apply this accounting
treatment and may be required to eliminate such regulatory assets
from its balance sheet. Although the potential effects of
deregulation cannot be determined at present, discontinuation of
the accounting treatment could have a material adverse effect on
the Company's results of operations in the period the write-off
is recorded. It is expected that cash flows and the financial
position of the Company would not be materially affected by the
discontinuation of the accounting treatment. The Company reported
approximately $236 million and $62 million of regulatory assets and
liabilities, respectively, including amounts recorded for deferred
income tax assets and liabilities of approximately $118 million and
$52 million, respectively, on its balance sheet at December 31,
1997.
The Company's generation assets are exposed to considerable
financial risks in a deregulated electric market. If market prices
for electric generation do not produce adequate revenue streams and
the enabling legislation or regulatory actions do not provide for
recovery of the resulting stranded costs, the Company could be
required to write down its investment in these assets. The Company
cannot predict whether any write-downs will be necessary and, if
they are, the extent to which they would adversely affect the
Company's results of operations in the period in which they are
recorded. As of December 31, 1997, the Company's net investment in
fossil/hydroelectric generation and nuclear generation assets was
approximately $977.1 million and $659.1 million, respectively.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The cash requirements of the Company arise primarily from its
operational needs and its construction program. The ability of the
Company to replace existing plant investments, as well as to expand
to meet future demand for electricity and gas, will depend upon its
ability to attract the necessary financial capital on reasonable
terms. The Company recovers the costs of providing services
through rates charged to customers. Rates for regulated services
are generally based on historical costs. As customer growth and
inflation occur and the Company continues its ongoing construction
program it is necessary to seek increases in rates. As a result
the Company's future financial position and results of operations
will be affected by its ability to obtain adequate and timely rate
and other regulatory relief.
6
On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which were
designed to produce additional revenues, based on a test year, of
approximately $67.5 million annually. The increase has been
implemented in two phases. The first phase, an increase in
revenues of approximately $59.5 million annually or 6.47%,
commenced in January 1996. The second phase, an increase in
revenues of approximately $8.0 million annually, based on a test
year, or .87%, was implemented in January 1997. The PSC
authorized a return on common equity of 12.0%. The PSC also
approved establishment of a Storm Damage Reserve Account capped at
$50 million to be collected through rates over a ten-year period.
Additionally, the PSC approved accelerated recovery of a
significant portion of the Company's electric regulatory assets
(excluding deferred income tax assets) and the remaining transition
obligation for postretirement benefits other than pensions,
changing the amortization periods to allow recovery by the end of
the year 2000. The Company's request to shift, for ratemaking
purposes, approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved. The Consumer Advocate appealed certain issues
in the order to the South Carolina Circuit Court, which affirmed
the PSC's decisions, and subsequently to the South Carolina Supreme
Court which is expected to hear the case and issue a ruling prior
to the end of 1998. While the outcome of this proceeding is
uncertain, the Company does not believe that any significant
adverse changes in the rate order is likely. The PSC's order does
not apply to wholesale electric revenues under the FERC's
jurisdiction, which constitute approximately two percent of the
Company's electric revenues. The FERC rejected the transfer of
depreciation reserves for rates subject to its jurisdiction.
During 1998 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 92%, after payment of dividends), and the issuance
and sale of debt securities and additional equity contributions
from SCANA. Short-term liquidity is expected to be provided
primarily by issuance of commercial paper. The timing and amount
of such sales and the type of securities to be sold will depend
upon market conditions and other factors.
The Company's revised estimates of its cash requirements for
construction and nuclear fuel expenditures, which are subject to
continuing review and adjustment, for 1998 and the two-year period
1999-2000 are as follows:
Type of Facilities 1999-2000 1998
(Millions of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $ 93 $ 56
Transmission. . . . . . . . . . . . . . . 31 16
Distribution. . . . . . . . . . . . . . . 126 46
Other . . . . . . . . . . . . . . . . . . 22 13
Nuclear Fuel. . . . . . . . . . . . . . . . 33 23
Gas . . . . . . . . . . . . . . . . . . . . 35 13
Common. . . . . . . . . . . . . . . . . . . 27 29
Other . . . . . . . . . . . . . . . . . . . - 1
Total . . . . . . . . . . . . . . $367 $197
The above estimates exclude AFC.
During 1997 the Company expended approximately $23.1 million
as part of a program to extend the operating lives of certain non-
nuclear generating facilities. Additional improvements to be made
under the program during 1998, included in the table above, are
estimated to cost approximately $57.4 million.
7
In addition to the Company's capital requirements for 1998
described above, approximately $47.7 million will be required for
refunding and retiring outstanding securities and obligations. For
the years 1999-2002, the Company has an aggregate of $301.8
million of long-term debt maturing (including approximately $69.2
million for sinking fund requirements, of which $68.7 million may
be satisfied by deposit and cancellation of bonds issued upon the
basis of property additions or bond retirement credits) and $2.2
million of purchase or sinking fund requirements for preferred
stock.
SCANA and Westvaco Corporation have formed a limited liability
company, Cogen South LLC, to build and operate a $170 million
cogeneration facility at Westvaco's Kraft Division Paper Mill in
North Charleston, South Carolina. The facility will provide
industrial process steam for the Westvaco paper mill and shaft
horsepower to enable the Company to generate up to 99 megawatts of
electricity. Construction financing is being provided to Cogen
South LLC by banks. In addition to the cogeneration LLC, Westvaco
has entered into a 20-year contract with the Company for all its
electricity requirements at the North Charleston mill at the
Company's standard industrial rate. Construction of the plant
began in September 1996 and it is expected to be operational in the
fall of 1998.
Financing Program
On April 24, 1997 the Company sold $100 million of 6.52%
cumulative preferred stock, par value $100 per share. Proceeds
from the sale were used to reduce short-term indebtedness incurred
for the Company's construction program, to refinance senior
securities and for general corporate purposes.
On October 28, 1997 SCE&G Trust I (the "Trust"), a Delaware
statutory business trust and a subsidiary of the Company, issued
$50 million of 7.55% Trust Preferred Securities, Series A. The
Trust used the proceeds from the sale to purchase unsecured 7.55%
junior subordinated debentures of the Company. The Company will
use the funds to redeem certain series of its preferred stock. The
financial statements of the Trust will be consolidated with those
of the Company.
The Company's First and Refunding Mortgage Bond Indenture,
dated April 1, 1945 (Old Mortgage), contains provisions prohibiting
the issuance of additional bonds thereunder (Class A Bonds) unless
net earnings (as therein defined) for twelve consecutive months out
of the fifteen months prior to the month of issuance are at least
twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1997 the
Bond Ratio was 4.32. The issuance of additional Class A Bonds also
is restricted to an additional principal amount equal to (i) 60% of
unfunded net property additions (which unfunded net property
additions totaled approximately $579 million at December 31, 1997),
(ii) retirements of Class A Bonds (which retirement credits totaled
$67.5 million at December 31, 1997), and (iii) cash on deposit with
the Trustee.
The Company has a bond indenture dated April 1, 1993 (New
Mortgage) covering substantially all of its electric properties
under which its future mortgage-backed debt (New Bonds) will be
issued. New Bonds are issued under the New Mortgage on the basis
of a like principal amount of Class A Bonds issued under the Old
Mortgage which have been deposited with the Trustee of the New
Mortgage (of which $185 million were available for such purpose at
December 31, 1997), until such time as all presently outstanding
Class A Bonds are retired. Thereafter, New Bonds will be issuable
on the basis of property additions in a principal amount equal to
70% of the original cost of electric and common plant properties
(compared to 60% of value for Class A Bonds under the Old
Mortgage), cash deposited with the Trustee, and retirement of New
Bonds. New Bonds will be issuable under the New Mortgage only if
adjusted net earnings (as therein defined) for twelve consecutive
months out of the eighteen months immediately preceding the month
of issuance are at least twice the annual interest requirements on
all outstanding bonds (including Class A Bonds) and New Bonds to be
outstanding (New Bond Ratio). For the year ended December 31, 1997
the New Bond Ratio was 5.87.
8
Without the consent of at least a majority of the total voting
power of the Company's preferred stock, the Company may not issue
or assume any unsecured indebtedness if, after such issue or
assumption, the total principal amount of all such unsecured
indebtedness would exceed 10% of the aggregate principal amount of
all of the Company's secured indebtedness and capital and surplus;
however, no such consent shall be required to enter into agreements
for payment of principal, interest and premium for securities
issued for pollution control purposes.
Pursuant to Section 204 of the Federal Power Act, the Company
must obtain the FERC authority to issue short-term debt. The FERC
has authorized the Company to issue up to $250 million of unsecured
promissory notes or commercial paper with maturity dates of twelve
months or less, but not later than December 31, 1999. Commercial
paper outstanding at December 31, 1997 was $13.3 million.
The Company had $315 million authorized and unused lines of
credit at December 31, 1997 including a credit agreement for a
maximum of $250 million to support the issuance of commercial
paper. Commercial paper outstanding at December 31, 1997 and
December 31, 1996 was $13.3 million and $66.1 million,
respectively. See "Fuel Financing Agreements" for a discussion of
Fuel Company credit agreements.
The Company's Restated Articles of Incorporation prohibit
issuance of additional shares of preferred stock without consent of
the preferred stockholders unless net earnings (as defined therein)
for the twelve consecutive months immediately preceding the month
of issuance are at least one and one-half times the aggregate of
all interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1997 the
Preferred Stock Ratio was 2.69.
The ratios of earnings to fixed charges (SEC Method) were
3.85, 3.80, 3.41, 3.46 and 3.57 for the years ended December 31,
1997, 1996, 1995, 1994 and 1993, respectively.
During 1997 the Company received $12.1 million in equity
contributions from SCANA. These contributions represented proceeds
from the sale of common stock through SCANA's Investor Plus Plan
and Stock Purchase Savings Program which in 1996 raised $4.4
million and $24.5 million, respectively, in equity capital.
Effective February 1, 1997 SCANA converted the Investor Plus Plan
from an original issue plan to a market purchase plan. The SPSP
converted from an original issue plan to a market purchase plan on
July 1, 1997.
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.
Fuel Financing Agreements
The Company has assigned to Fuel Company all of its rights and
interests in its various contracts relating to the acquisition and
ownership of nuclear and fossil fuels. To finance nuclear and
fossil fuels and sulfur dioxide emission allowances, Fuel Company
issues, from time to time, commercial paper which is supported, up
to $125 million, by an irrevocable revolving credit agreement which
expires December 19, 2000. Accordingly, the amounts outstanding
have been included in long-term debt. This commercial paper and
amounts outstanding under the revolving credit agreement, if any,
are guaranteed by the Company. The full amount of the credit
agreement was available at December 31, 1997.
At December 31, 1997 commercial paper outstanding was
approximately $80.3 million at a weighted average interest rate
of 5.87%. (See Notes 1M and 4 of Notes to Consolidated Financial
Statements.)
9
ELECTRIC OPERATIONS
Electric Sales
In 1997 residential sales of electricity accounted for 41% of
electric sales revenues; commercial sales 31%; industrial sales
20%; sales for resale 2%; and all other 6%. KWH sales by
classification for the years ended December 31, 1997 and 1996 are
presented below:
Sales
KWH %
Classification 1997 1996 Change
(thousands)
Residential 5,647,185 5,939,703 (4.92)
Commercial 5,321,738 5,222,517 1.90
Industrial 5,434,231 5,320,515 2.14
Sale for resale 485,206 1,023,211 (52.58)
Other 505,808 505,793 -
Total Territorial 17,394,168 18,011,739 (3.43)
Negotiated Market Share Tariff 1,459,097 895,016 63.02
Total 18,853,265 18,906,755 (0.28)
Sales for resale includes electricity furnished for resale to
three municipalities and two electric cooperatives. One electric
cooperative has notified the Company of its intent to terminate in
the year 2000 its wholesale power contract with the Company and bid
out its electric requirements. Sales under the Negotiated Market
Sales Tariff during 1997 includes sales to 28 investor-owned
utilities, three electric cooperatives, two municipalities and
three federal/state electric agencies. During 1996, sales under
the Negotiated Market Sales Tariff includes sales to thirteen
investor-owned utilities, one electric cooperative and two state
electric agencies.
The electric sales volume for residential sales decreased for
1997 as a result of milder weather. The decrease in sales for
resale and the increase of sales under the Negotiated Market Sales
Tariff was a result of a municipality terminating its wholesale
power contract and transferring to a Negotiated Market Rate. During
1997 the Company recorded a net increase of 10,583 electric
customers, increasing its total customers to 503,929. The all-time
peak demand of 3,734 MW was set on August 13, 1997.
Electric Interconnections
The Company purchases all of the electric generation of
Williams Station, owned by GENCO, under a Unit Power Sales
Agreement which has been approved by the FERC. Williams Station
has a generating capacity of 560 MW.
10
The Company's transmission system is part of the
interconnected grid extending over a large part of the southern and
eastern portions of the nation. The Company, Virginia Power
Company, Duke Power Company, Carolina Power & Light Company,
Yadkin, Incorporated and PSA are members of the Virginia-Carolinas
Reliability Group, one of the several geographic divisions within
the Southeastern Electric Reliability Council. This Council
provides for coordinated planning for reliability among bulk power
systems in the Southeast. The Company is also interconnected with
Georgia Power Company, Savannah Electric & Power Company,
Oglethorpe Power Corporation and Southeastern Power
Administration's Clark Hill Project.
Fuel Costs
The following table sets forth the average cost of nuclear
fuel and coal and the weighted average cost of all fuels (including
oil and natural gas) used by the Company and GENCO for the years
1995-1997.
1997 1996 1995
Nuclear:
Per million BTU $ .47 $ .47 $ .48
Coal:
Company:
Per ton $38.22 $39.27 $40.01
Per million BTU 1.54 1.55 1.57
GENCO:
Per ton $44.49 $41.66 $42.21
Per million BTU 1.61 1.62 1.63
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.52 $ 1.52 $ 1.26
The fuel costs for 1995 shown above exclude the effects of a
PSC-approved offsetting of fuel costs through the application of
credits carried on the Company's books as a result of a 1980
settlement of certain litigation.
Fuel Supply
The following table shows the sources and approximate
percentages of total for the Company's KWH generation (including
Williams Station) by each category of fuel for the years 1995-1997
and the estimates for 1998 and 1999.
Percent of Total KWH Generated
Estimated Actual
1999 1998 1997 1996 1995
Coal 73% 69% 63% 71% 65%
Nuclear 22 26 31 24 27
Hydro 5 5 6 5 5
Natural Gas & Oil - - - - 3
100% 100% 100% 100% 100%
Coal is used at all five of the Company's major fossil fuel-
fired plants and GENCO's Williams Station. Unit train deliveries
are used at all of these plants and truck deliveries are used at
three of these plants. On December 31, 1997 the Company had
approximately a 41-day supply of coal in inventory and GENCO had
approximately a 30-day supply.
11
The supply of coal is obtained through contracts and purchases
on the spot market. Spot market purchases are expected to continue
for coal requirements in excess of those provided by the Company's
existing contracts. Contracts for the purchase of coal represent
96.1% of estimated requirements for 1998 (approximately 5.8
million tons, including requirements of Williams Station).
The supply of contract coal is purchased from nine suppliers
located in eastern Kentucky, Tennessee and southwest Virginia.
Contract commitments, which expire at various times from 1998-2006,
approximate 5.5 million tons annually. Sulfur restrictions on the
contract coal range from .75% to 2%.
The Company believes that its operations are in substantial
compliance with all existing regulations relating to the discharge
of sulfur dioxide. The Company is unaware that any more stringent
sulfur content requirements for existing plants are contemplated at
the State level by DHEC. However, the Company will be required to
meet the more stringent Federal emissions standards established by
the Clean Air Act (see "Environmental Matters").
The Company has adequate supplies of uranium or enriched
uranium product under contract to manufacture nuclear fuel for
Summer Station through 2005. The following table summarizes all
contract commitments for the stages of nuclear fuel assemblies:
Remaining Expiration
Commitment Contractor Regions(1) Date
Enrichment USEC (2) 13-18 2005
Fabrication Westinghouse 13-21 2009
(1) A region represents approximately one-third to one-half of the
nuclear core in the reactor at any one time. Region no. 13 was
loaded in 1997 and Region no. 14 will be loaded in 1999.
(2) Contract provisions for the delivery of enriched uranium
product encompass uranium supply and conversion and enrichment
services.
The Company has on-site spent nuclear fuel storage capability
until at least 2009 and expects to be able to expand its storage
capacity to accommodate the spent fuel output for the life of the
plant through rod consolidation, dry cask storage or other
technology as it becomes available. In addition, there is
sufficient on-site storage capacity over the life of Summer Station
to permit storage of the entire reactor core in the event that
complete unloading should become desirable or necessary for any
reason. (See "Nuclear Fuel Disposal" under "Environmental Matters"
for information regarding the contract with the DOE for disposal of
spent fuel.)
Decommissioning
Decommissioning of Summer Station is presently scheduled to
commence when the operating license expires in the year 2022.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning costs is
referred to as COMReP (Cost of Money Reduction Plan). Under this
plan, funds collected through rates ($3.2 million in 1997 and 1996)
are used to pay premiums on insurance policies on the lives of
certain Company personnel. The Company is the beneficiary of
these policies. Through these insurance contracts, the
12
Company is able to take advantage of income tax benefits and accrue
earnings on the fund on a tax-deferred basis at a rate higher than
can be achieved using more traditional funding approaches. Amounts
for decommissioning collected through electric rates, insurance
proceeds, and interest on proceeds less expenses are transferred by
the Company to an external trust fund in compliance with the
financial assurance requirements of the NRC. Management intends
for the fund, including earnings thereon, to provide for all
eventual decommissioning expenditures on an after-tax basis. The
trust's sources of decommissioning funds under the COMReP program
include investment components of life insurance policy proceeds,
return on investment and the cash transfers from the Company
described above. The Company records its liability for
decommissioning costs in deferred credits.
GAS OPERATIONS
Gas Sales
In 1997 residential sales accounted for 43% of gas sales
revenues; commercial sales 31%; industrial sales 26%. Dekatherm
sales by classification for the years ended December 31, 1997 and
1996 are presented below:
Sales
Dekatherms %
Classification 1997 1996 Change
Residential 11,919,843 14,108,058 (15.5)
Commercial 10,904,445 11,027,830 (1.1)
Industrial 15,729,424 13,909,258 13.1
Transportation gas 2,677,448 3,108,058 (13.9)
Total 41,231,160 42,153,204 (2.2)
The gas sales volume decreased for 1997 as a result of milder
weather which was offset by increases in contract prices for
industrial interruptible customers.
During 1997 the Company recorded a net increase of 4,139 gas
customers, increasing its total customers to 252,635.
The Company purchases all of its natural gas from Pipeline
Corporation.
The demand for gas is affected by conservation, the weather,
the price relationship between gas and alternate fuels and other
factors.
The deregulation of natural gas prices at the wellhead and the
changes in the prices of natural gas that have occurred under
Federal regulation have resulted in the development of a spot
market for natural gas in the producing areas of the country.
Pipeline Corporation has been successful in purchasing lower cost
natural gas in the spot market and arranging for its transportation
to South Carolina.
13
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts
with producers and marketers on a short-term basis at current price
indices and on a long-term basis for reliability assurance at index
prices plus a gas inventory charge. The gas is brought to South
Carolina through transportation agreements with both Southern
Natural and Transco, which expire at various times from 1998 to
2017. The volume of gas which Pipeline Corporation is entitled to
transport under these contracts on a firm basis is shown below:
Maximum Daily
Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 188,000
Transco Firm Transportation 105,000
Total 293,000
Under a contract with Pipeline Corporation, the Company's
maximum daily contract demand is 224,270 dekatherms. The contract
allows the Company to receive amounts in excess of this demand
based on availability.
The average cost per MCF of natural gas purchased from
Pipeline Corporation was approximately $3.96 in 1997 compared to
$4.30 in 1996.
To meet the requirements of the Company and its other high
priority natural gas customers during periods of maximum demand,
Pipeline Corporation supplements its supplies of natural gas from
two LNG plants. The LNG plants are capable of storing the lique-
fied equivalent of 1,900,000 MCF of natural gas, of which
approximately 1,286,570 MCF were in storage at December 31, 1997.
On peak days the LNG plants can regasify up to 150,000 MCF per
day. Additionally, Pipeline Corporation had contracted for
6,447,214 MCF of natural gas storage space of which 4,197,154 MCF
were in storage on December 31, 1997.
The Company believes that supplies under contract and
available for spot market purchase are adequate to meet existing
customer demands and to accommodate growth.
Curtailment Plans
The FERC has established allocation priorities applicable to
firm and interruptible capacities on interstate pipeline companies
which require Southern Natural and Transco to allocate capacity to
Pipeline Corporation. The FERC allocation priorities are not
applicable to deliveries by the Company to its customers, which are
governed by a separate curtailment plan approved by the PSC.
REGULATION
General
The Company is subject to the jurisdiction of the PSC as to
retail electric, gas and transit rates, service, accounting,
issuance of securities (other than short-term promissory notes) and
other matters. The Company is subject to regulation under the
Federal Power Act, administered by the FERC and the DOE, in the
transmission of electric energy in interstate commerce and in the
sale of electric energy at wholesale for resale, as well as with
respect to licensed hydroelectric projects and certain other
matters, including accounting and the issuance of short-term
promissory notes. (See "Capital Requirements and Financing
Program").
14
The Company holds licenses under the Federal Water Power Act
or the Federal Power Act with respect to all its hydroelectric
projects. The expiration dates of the licenses covering the
projects are as follows:
Project Capability (KW) License Expiration Date
Neal Shoals 5,000 2036
Stevens Creek 9,000 2025
Columbia 10,000 2000
Saluda 206,000 2007
Parr Shoals 14,000 2020
Fairfield Pumped Storage 512,000 2020
The Company filed a notice of intent to file an application
for a new license for Columbia on June 29, 1995. The application
for the new license will be filed by June 30, 1998.
At the termination of a license under the Federal Power Act,
the United States government may take over the project covered
thereby, or the FERC may extend the license or issue a license to
another applicant. If the Federal government takes over a project
or the FERC issues a license to another applicant, the original
licensee is entitled to be paid its net investment in the project,
not to exceed fair value, plus severance damages.
In May 1996 the FERC approved the Company's application
establishing open access transmission tariffs and requesting
authorization to sell bulk power to wholesale customers at market-
based rates.
Nuclear Regulatory Commission
The Company is subject to regulation by the NRC with respect
to the ownership and operation of Summer Station. The NRC's
jurisdiction encompasses broad supervisory and regulatory powers
over the construction and operation of nuclear reactors, including
matters of health and safety, antitrust considerations and
environmental impact. In addition, the Federal Emergency
Management Agency is responsible for the review, in conjunction
with the NRC, of certain aspects of emergency planning relating to
the operation of nuclear plants.
Summer Station has received a category one rating from the
Institute of Nuclear Power Operations (INPO) in the last five out
of six evaluations. The category one rating is the highest given
by INPO for a nuclear plant's overall operations.
In 1997 Summer Station successfully completed its refueling
outage ahead of schedule and under budget.
In 1996, the NRC completed the Systematic Assessment of
Licensee Performance (SALP) for Summer Station. The station was
assessed in four functional areas. The results of the assessment
identified superior performance in Plant Operations, Maintenance
and Engineering and good performance in Plant Support. Superior is
the highest assessment given by the NRC.
15
National Energy Policy Act of 1992 and FERC Orders 636 and 888
The Company's regulated business operations were impacted by
the NEPA and FERC Orders No. 636 and 888. NEPA was designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. See "Competition" for a discussion of FERC
Order 888. Order No. 636 was intended to deregulate the markets
for interstate sales of natural gas by requiring that pipelines
provide transportation services that are equal in quality for all
gas suppliers whether the customer purchases gas from the pipeline
or another supplier. In the opinion of the Company, it continues
to be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any material
adverse impact on the results of operations, cash flows, financial
position or business prospects.
RATE MATTERS
The following table presents a summary of significant rate
activity for the years 1993-1997 based on test years:
REQUESTED GRANTED
Date of % % of
General Rate Application/ Amount Increase Date of Amount Increase
Applications Hearing (Millions) Requested Order (Millions) Granted
PSC
Electric
Retail 07/10/95 $ 76.7 8.4% 1/09/96 $67.5 88%
Retail 12/07/92 $ 72.0* 11.4% 6/07/93 $60.5 84%
* As modified to reflect lowering of rate of return the Company was
seeking.
On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which was
designed to produce additional revenues, based on a test year, of
approximately $67.5 million annually. The increase has been
implemented in two phases. The first phase, an increase in
revenues of approximately $59.5 million annually or 6.47%,
commenced in January 1996. The second phase, an increase in
revenues of approximately $8.0 million annually, or .87%, was
implemented in January 1997. The PSC authorized a return on
common equity of 12.0%. The PSC also approved establishment of a
Storm Damage Reserve Account capped at $50 million to be collected
through rates over a ten-year period. Additionally, the PSC
approved accelerated recovery of a significant portion of the
Company's electric regulatory assets (excluding deferred income tax
assets) and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods to
allow recovery by the end of the year 2000. The Company's request
to shift, for ratemaking purposes, approximately $257 million of
depreciation reserves from transmission and distribution assets to
nuclear production assets was also approved. The Consumer Advocate
appealed certain issues in the order to the South Carolina Circuit
Court, which affirmed the PSC's decisions, and subsequently to the
South Carolina Supreme Court which is expected to hear the case and
issue a ruling prior to the end of 1998. While the outcome of this
proceeding is uncertain, the Company does not believe that any
significant adverse changes in the rate order is likely. The
PSC's order does not apply to wholesale electric revenues under the
FERC's jurisdiction, which constitute approximately two percent of
the Company's electric revenues. The FERC rejected the transfer of
depreciation reserves for rates subject to its jurisdiction.
16
In 1994 the PSC issued an order approving the Company's request
to recover through a billing surcharge to its gas customers the
costs of environmental cleanup at the sites of former manufactured
gas plants. The billing surcharge is subject to annual review and
provides for the recovery of substantially all actual and projected
site assessment and cleanup costs and environmental claims
settlements for the Company's gas operations that had previously
been deferred. In October 1997, as a result of the annual review,
the PSC approved the Company's request to increase the billing
surcharge from $.006 per therm to $.011 per therm which should
enable the Company to recover the remaining balance of $29.6
million by December 2002.
In September 1992 the PSC issued an order granting the Company
a $.25 increase in transit fares from $.50 to $.75 in both Columbia
and Charleston, South Carolina; however, the PSC also required $.40
fares for low-income customers and denied the Company's request to
reduce the number of routes and frequency of service. The new
rates were placed into effect in October 1992. The Company
appealed the PSC's order to the Circuit Court, which in May 1995
ordered the case back to the PSC for reconsideration of several
issues including the low income rider program, routing changes, and
the $.75 fare. The Supreme Court declined to review an appeal of
the Circuit Court decision and dismissed the case. The PSC and
other intervenors filed another Petition for Reconsideration, which
the Supreme Court denied. The PSC and other intervenors filed
another appeal to the Circuit Court which the Circuit Court denied
in an Order dated May 9, 1996. In this Order, the Circuit Court
upheld its previous Orders and remanded them back to the PSC.
During August 1996, the PSC heard oral arguments on the Orders on
remand for the Circuit Court. On September 30, 1996, the PSC
issued an order affirming its previous orders and denied the
Company's request for reconsideration. The Company has appealed
these two PSC orders to the Circuit Court where they are awaiting
action.
Fuel Cost Recovery Procedures
The PSC has established a fuel cost recovery procedure which
determines the fuel component in the Company's retail electric base
rates annually based on projected fuel costs for the ensuing
twelve-month period, adjusted for any overcollection or
undercollection from the preceding twelve-month period. The
Company has the right to request a formal proceeding at any time
should circumstances dictate such a review.
In the April 1997 annual review of the fuel cost component of
electric rates, the PSC decreased the rate from 13.10 mills per KWH
to 12.85 mills per KWH, a monthly decrease of $0.25 for an average
customer using 1,000 KWH a month.
The Company's gas rate schedules and contracts include
mechanisms which allow it to recover from its customers changes in
the actual cost of gas. The Company's firm gas rates allow for the
recovery of a fixed cost of gas, based on projections, as
established by the PSC in annual gas cost and gas purchase practice
hearings. Any differences between actual and projected gas costs
are deferred and included when projecting gas costs during the next
annual gas cost recovery hearing.
In the October 1997 review the PSC decreased the base cost of
gas from 51.260 cents per therm to 48.182 cents per therm which
resulted in a monthly decrease of $3.08 (including applicable
taxes) based on an average of 100 therms per month on a residential
bill during the heating season.
17
ENVIRONMENTAL MATTERS
General
Federal and state authorities have imposed environmental
regulations and standards requirements relating primarily to air
emissions, wastewater discharges and solid, toxic and hazardous
waste management. Developments in these areas may require that
equipment and facilities be modified, supplemented or replaced.
The ultimate effect of these regulations and standards upon
existing and proposed operations cannot be forecast.
Capital Expenditures
In the years 1995 through 1997, capital expenditures for
environmental control amounted to approximately $48.5 million. In
addition, approximately $17.1 million, $12.2 million and $10.4
million of environmental control expenditures were made during
1997, 1996 and 1995, respectively, which was included in "Other
operation" and "Maintenance" expenses. It is not possible to
estimate all future costs for environmental purposes but forecasts
for capitalized expenditures are $48.0 million for 1997 and $91.2
million for the four-year period 1999 through 2002. These
expenditures are included in the Company's construction program.
Air Quality Control
The Clean Air Act requires electric utilities to reduce
emissions of sulfur dioxide and nitrogen oxide by the year 2000.
These requirements are being phased in over two periods. The first
phase had a compliance date of January 1, 1995 and the second,
January 1, 2000. The Company's facilities did not require
modifications to meet the requirements of Phase I. The Company
will most likely meet the Phase II requirements through the burning
of natural gas and/or lower sulfur coal in its generating units and
the purchase and use of sulfur dioxide emission allowances. Low
nitrogen oxide burners are being installed to reduce nitrogen oxide
emissions to the levels required by Phase II. Air toxicity
regulations for the electric generating industry are likely to be
promulgated around the year 2000.
The Company filed with DHEC compliance plans related to Phase
II sulfur dioxide requirements in 1995, and Phase II nitrogen oxide
requirements in December, 1997. The Company currently estimates
that air emissions control equipment will require capital
expenditures of $90.3 million over the 1998-2002 period to
retrofit existing facilities, with increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2007, the Company
anticipates total capital expenditures of approximately $185
million.
Water Quality Control
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a national
permit program. Discharge permits have been issued for all and
renewed for nearly all of the Company's and GENCO's generating
units. Concurrent with renewal of these permits the permitting
agency has implemented a more rigorous program in monitoring and
controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. The Company has been developing
compliance plans to meet these initiatives. Amendments to the
Clean Water Act proposed in Congress include several provisions
which, if passed, could prove costly to the Company. These
include, but are not limited to, limitations to mixing zones and
the implementation of technology-based standards.
18
Comprehensive Environmental Recovery, Compensation and Liability
Act (Superfund) and Environmental Assessment Program
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
an estimate is made of the amount of expenditures, if any,
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, accrued and actually expended to
date for site assessments and cleanup relate primarily to regulated
operations; such amounts are deferred and are being amortized and
recovered through rates over a five-year period for electric
operations and an eight-year period for gas operations. The
Company has also recovered portions of its environmental
liabilities through settlements with various insurance carriers.
Deferred amounts, net of amounts recovered through rates and
insurance settlements, totaled $32.4 million and $41.4 million at
December 31, 1997 and 1996, respectively. The deferral includes
the costs estimated to be associated with the matters discussed
below.
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 before cleanup is initiated.
The PRPs have agreed with the EPA to participate in an
innovative approach to site investigation and cleanup called
"Superfund Accelerated Cleanup Model," allowing the pre-
cleanup site investigation process to be compressed
significantly. The 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
conditionally approved a Remedial Investigation Report in March
1997. Although the Company is continuing to investigate cost-
effective clean-up methodologies, further work is pending EPA
approval of the final draft of the Remedial Investigation
Report.
In October 1996 the City of Charleston and the Company settled
all environmental claims the City may have had against the
Company involving the Calhoun Park area for a payment of $26
million over four years (1996-1999) by the Company to the City.
The Company is recovering the amount of the settlement, which
does not encompass site assessment and cleanup costs, through
rates in the same manner as other amounts accrued for site
assessments and cleanup as discussed above. As part of the
environmental settlement, the Company has agreed to construct
an 1,100 space parking garage on the Calhoun Park site and to
transfer the facility to the City in exchange for a 20-year
municipal bond backed by revenues from the parking garage and
a mortgage on the parking garage. Construction is expected to
begin in 1998. The total amount of the bond is not to exceed
$16.9 million, the maximum expected project cost.
The Company owns three other decommissioned manufactured gas
plant sites which contain residues of by-product chemicals.
The Company is investigating the sites to monitor the nature
and extent of the residual contamination.
19
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of
1991 directed the DHEC to promulgate regulations for the disposal
of industrial solid waste. DHEC has proposed a regulation, which
if adopted as a final regulation in its present form, would
significantly increase the Company's costs of construction and
operation of existing and future ash management facilities.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 requires that the United
States government make available by 1998 a permanent repository
for high-level radioactive waste and spent nuclear fuel and imposes
a fee of 1.0 mil per KWH of net nuclear generation after April 7,
1983. Payments, which began in 1983, are subject to change and will
extend through the operating life of Summer Station. The Company
entered into a contract with the DOE on June 29, 1983, providing
for permanent disposal of its spent nuclear fuel by the DOE. The
DOE presently estimates that the permanent storage facility will
not be available until 2010. The Company has on-site spent nuclear
fuel storage capability until at least 2009 and expects to be able
to expand its storage capacity to accommodate the spent nuclear
fuel output for the life of the plant through rod consolidation,
dry cask storage or other technology as it becomes available. The
Act also imposes on utilities the primary responsibility for
storage of their spent nuclear fuel until the repository is
available.
OTHER MATTERS
With regard to the Company's insurance coverage for Summer
Station, reference is made to Note 10B of Notes to Consolidated
Financial Statements which is incorporated herein by reference.
ITEM 2. PROPERTIES
The Company's bond indentures, securing the First and
Refunding Mortgage Bonds and First Mortgage Bonds issued
thereunder, constitute direct mortgage liens on substantially all
of its property.
20
ELECTRIC
The following table gives information with respect to the
Company's electric generating facilities.
Net Generating
Present Year Capability
Facility Fuel Capability Location In-Service (KW)(1)
Steam
Urquhart Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 430,000
Wateree Coal Eastover, SC 1970 700,000
Summer (2) Nuclear Parr, SC 1984 635,000
D-Area (3) Coal DOE Savannah
River Site, SC 1995 35,000
Cope (4) Coal Cope, SC 1996 408,000
Gas Turbines
Burton Gas/Oil Burton, SC 1961 28,500
Faber Place Gas Charleston, SC 1961 9,500
Hardeeville Oil Hardeeville, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr Gas/Oil Parr, SC 1970 60,000
Williams (5) Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000
Hydro
Neal Shoals Carlisle, SC 1905 5,000
Parr Shoals Parr, SC 1914 14,000
Stevens Creek Martinez, GA 1914 9,000
Columbia Columbia, SC 1927 10,000
Saluda Irmo, SC 1930 206,000
Pumped Storage
Fairfield Parr, SC 1978 512,000
Total (6) 3,790,000
(1) Summer rating.
(2) Represents the Company's two-thirds portion of the Summer
Station.
(3) This plant is operated under lease from the DOE and is
dispatched to DOE's Savannah River Site steam needs. "Net
Generating Capability" for this plant is expected average
hourly output. The lease expires on October 1, 2005.
(4) Plant began commercial operation in January 1996.
(5) The two gas turbines at Williams were purchased upon
expiration of the lease on June 29, 1997.
(6) Excludes Williams Station.
21
The Company owns 428 substations having an aggregate
transformer capacity of 21,356,393 KVA. The transmission system
consists of 3,122 miles of lines and the distribution system
consists of 16,129 pole miles of overhead lines and 3,500 trench
miles of underground lines.
GAS
Natural Gas
The Company's gas system consists of approximately 11,728
miles of distribution mains and related service facilities.
Propane
The Company has propane air peak shaving facilities which can
supplement the supply of natural gas by gasifying propane to yield
the equivalent of 102,000 MCF per day of natural gas. These
facilities can store the equivalent of 430,405 MCF of natural gas.
TRANSIT
The Company owns 61 motor coaches used in the operation of the
Columbia transit system. The Columbia system is comprised of
fifteen routes covering 177 miles.
Effective October 1, 1996, the Company transferred ownership
and operation of the Charleston transit system to the City of
Charleston. As part of the transfer, the Company conveyed ownership
to the City of Charleston facilities, equipment and four motor
coaches used in the operation of the transit system. The City and
the Company entered into an interim operating agreement, with
provisions for renewing, whereby the Company will operate the
system for the City until a Regional Transit Authority is
established. The Company and the City have agreed upon a rate
structure designed to allow the Company to recover its costs of
operating the Charleston transit system. The Charleston system is
composed of fourteen routes covering 110 miles.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1.,
"BUSINESS - RATE MATTERS" and "BUSINESS - ENVIRONMENTAL MATTERS -
Comprehensive Environmental Recovery, Compensation and Liabilities
Act (Superfund) and Environmental Assessment Program" and Note 10
of Notes to Consolidated Financial Statements appearing in Item 8.,
"FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
All of the Company's common stock is owned by SCANA and
therefore there is no market for such stock. During 1997 and 1996
the Company paid $141.4 million and $132.9 million, respectively,
in cash dividends to SCANA.
SECURITIES RATINGS (As of December 31, 1997)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
First First and Trust
Rating Mortgage Refunding Preferred Preferred Commercial
Agency Bonds Mortgage Bonds Stock Securities Paper
Duff &
Phelps A+ A+ A - D-1
Moody's A1 A1 a2 a2 P-1
Standard
& Poor's A A A- A- A-1
Further reference is made to Note 5 of Notes to Consolidated
Financial Statements.
The Restated Articles of Incorporation of the Company and the
Indenture underlying its First and Refunding Mortgage Bonds contain
provisions that may limit the payment of cash dividends on common
stock. In addition, with respect to hydroelectric projects, the
Federal Power Act may require the appropriation of a portion of the
earnings therefrom. At December 31, 1997 approximately $21.5
million of retained earnings were restricted as to payment of cash
dividends on common stock.
22
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1997 1996 1995 1994 1993
Statement of Income Data (Millions of dollars, except statistics)
Operating Revenues $1,338 $1,345 $1,211 $1,181 $1,118
Operating Income 282 286 256 230 219
Other Income 9 4 9 7 7
Net Income 195 190 169 152 146
Earnings Available for Common Stock 186 185 163 146 140
Balance Sheet Data
Utility Plant, Net $4,457 $3,197 $3,158 $2,998 $2,687
Total Assets 4,054 3,959 3,802 3,587 3,190
Capitalization:
Common equity 1,447 1,413 1,315 1,133 1,051
Preferred Stock (Not subject
to purchase or sinking funds) 106 26 26 26 26
Preferred Stock, Net (Subject to
purchase or sinking funds) 12 43 46 50 53
Company - Obligated mandatorily
redeemable preferred securities of
the Company's Subsidiary Trust, SCE&G
Trust I, holding solely $50 million,
principal amount of 7.55% of Junior
Subordinated Debentures of the Company,
due 2027 50 - - - -
Long-term debt, net 1,262 1,277 1,279 1,231 1,097
Total Capitalization $2,877 $2,759 $2,666 $2,440 $2,227
Other Statistics
Electric:
Customers (Year-End) 503,929 493,346 484,381 476,438 468,901
Total sales (Million KWH) 17,395 18,012 17,585 16,840 16,889
Residential:
Average annual use per customer (KWH) 13,214 14,149 13,859 13,048 14,077
Average annual rate per KWH $.0799 $.0785 $.0747 $.0743 $.0707
Generating capability - Net MW (Year-End) 4,350 4,316 4,282 3,876 3,864
Territorial peak demand - Net MW 3,734 3,698 3,683 3,444 3,557
Gas:
Customers (Year-End) 252,635 248,496 243,342 238,433 221,278
Sales, excluding transportation
(Thousand Therms) 385,537 390,451 362,384 322,837 267,335
Residential:
Average annual use per customer (Therms) 531 639 570 538 606
Average annual rate per therm $.86 $.74 $.82 $.84 $.76
</TABLE
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or
elsewhere in this annual report) which are not statements of
historical fact are intended to be, and are hereby identified as,
"forward looking statements" for purposes of the safe harbor
provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended.
Readers are cautioned that any such forward-looking statements are
not guarantees of future performance and involve a number of risks
and uncertainties, and that actual results could differ materially
from those indicated by such forward-looking statements. Important
factors that could cause actual results to differ materially from
those indicated by such forward-looking statements include, but are
not limited to, the following: (1) that the information is of a
preliminary nature and may be subject to further and/or continuing
review and adjustment, (2) changes in the utility regulatory
environment, (3) changes in the economy in areas served by the
Company's subsidiaries, (4) the impact of competition from
other energy suppliers, (5) the management of the Company's
operations (6) growth opportunities for the Company's regulated and
diversified subsidiaries, (7) the results of financing efforts, (8)
changes in the Company's accounting policies, (9) weather
conditions in areas served by the Company's utility subsidiaries,
(10) performance of the telecommunications companies in which the
Company has made significant investments, (11) inflation, (12)
changes in environmental regulations and (13) 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.
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulation.
Deregulation of electric wholesale and retail markets is creating
opportunities to compete for new and existing customers and
markets. As a result, profit margins and asset values of some
utilities could be adversely affected. Legislative initiatives at
the Federal and state levels are being considered and, if enacted,
could mandate market deregulation. The pace of deregulation, the
future prices of electricity, and the regulatory actions which may
be taken by the PSC and the FERC in response to the changing
environment cannot be predicted. However, the FERC, in issuing
Order 888 in April 1996, has accelerated competition among electric
utilities by providing for open access to wholesale transmission
service. Order 888 requires utilities under FERC jurisdiction that
own, control or operate transmission lines to file
nondiscriminatory open access tariffs that offer to others the same
transmission service they provide themselves. The FERC has also
permitted utilities to seek recovery of wholesale stranded costs
from departing customers by direct assignment. Approximately two
percent of the Company's electric revenue is under FERC
jurisdiction for the purpose of setting rates for wholesale
service. Legislation is pending in South Carolina that would
deregulate the state's retail electric market and enable customers
to choose their supplier of electricity. The Company is not able
to predict whether the legislation will be enacted and, if it is,
the conditions it will impose on utilities that currently operate
in the state and future market participants.
The Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company operates
Strategic Business Units. Maintaining a competitive cost structure
is of paramount importance in the Company's strategic plan. The
Company has undertaken a variety of initiatives, including
reductions in operation and maintenance costs and in staffing
levels, the accelerated recovery of the Company's electric
regulatory assets and the shift, for retail ratemaking purposes
only, of depreciation reserves from transmission and distribution
assets to nuclear production assets. The Company has also
established open access transmission tariffs and is selling bulk
power to wholesale customers at market-based rates. Significant
new customer and management information systems will be implemented
in 1998. Marketing of services to commercial and industrial
customers has been increased significantly. The Company has
obtained long term power supply contracts with a significant
portion of its industrial customers. The Company believes that
these actions as well as numerous others that have been and will be
taken demonstrate its ability and commitment to succeed in the new
operating environment to come.
24
Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment occur,
the Company may no longer be eligible to apply this accounting
treatment and may be required to eliminate such regulatory assets
from its balance sheet. Although the potential effects of
deregulation cannot be determined at present, discontinuation of
the accounting treatment could have a material adverse effect on
the Company's results of operations in the period the write-off is
recorded. It is expected that cash flows and the financial
position of the Company would not be materially affected by the
discontinuation of the accounting treatment. The Company reported
approximately $236 million and $62 million of regulatory assets and
liabilities, respectively, including amounts recorded for deferred
income tax assets and liabilities of approximately $118 million and
$52 million, respectively, on its balance sheet at December 31,
1997.
The Company's generation assets are exposed to considerable
financial risks in a deregulated electric market. If market prices
for electric generation do not produce adequate revenue streams and
the enabling legislation or regulatory actions do not provide for
recovery of the resulting stranded costs, the Company could be
required to write down its investment in these assets. The Company
cannot predict whether any write-downs will be necessary and, if
they are, the extent to which they would adversely affect the
Company's results of operations in the period in which they are
recorded. As of December 31, 1997, the Company net investment in
fossil\hydroelectric generation and nuclear generation assets was
$977.1 million and $659.1 million, respectively.
LIQUIDITY AND CAPITAL RESOURCES
The cash requirements of the Company arise primarily from its
operational needs and its construction program. The ability of the
Company to replace existing plant investment, as well as to expand
to meet future demand for electricity and gas, will depend upon its
ability to attract the necessary financial capital on reasonable
terms. The Company recovers the costs of providing services
through rates charged to customers. Rates for regulated services
are generally based on historical costs. As customer growth and
inflation occur and the Company continues its ongoing construction
program, it is necessary to seek increases in rates. As a result,
the Company's future financial position and results of operations
will be affected by its ability to obtain adequate and timely rate
and other regulatory relief.
SCANA and Westvaco Corporation have formed a limited liability
company, Cogen South LLC, to build and operate a $170 million
cogeneration facility at Westvaco's Kraft Division Paper Mill in
North Charleston, South Carolina. The facility will provide
industrial process steam for the Westvaco paper mill and shaft
horsepower to enable the Company to generate up to 99 megawatts of
electricity. Construction financing is being provided to Cogen
South LLC by banks. In addition to the cogeneration LLC, Westvaco
has entered into a 20-year contract with the Company for all its
electricity requirements at the North Charleston mill at the
Company's standard industrial rate. Construction of the plant
began in September 1996 and it is expected to be operational in the
fall of 1998.
On August 7, 1996 the City of Charleston executed 30-year
electric and gas franchise agreements with the Company. In
consideration for the electric franchise agreement, the Company is
paying the City $25 million over seven years (1996 through 2002)
and has donated to the City the existing transit assets in
Charleston. The $25 million is included in electric plant-in-
service. In settlement of environmental claims the City may have
had against the Company involving the Calhoun Park area, where the
Company and its predecessor companies operated a manufactured gas
plant until the 1960's, the Company is paying the City $26 million
over a four-year period (1996 through 1999). As part of the
environmental settlement, the Company has agreed to construct an
1,100 space parking garage on the Calhoun Park site and to transfer
the facility to the City in exchange for a 20-year municipal bond
backed by revenues from the parking garage and a mortgage on the
parking garage. The total amount of the bond is not to exceed
$16.9 million, the maximum expected project cost.
25
The revised estimated primary cash requirements for 1998,
excluding requirements for fuel liabilities and short-term
borrowings and including notes payable to affiliated companies, and
the actual primary cash requirements for 1997 are as follows:
1998 1997
(Millions of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $175 $201
Nuclear fuel expenditures 23 31
Maturing obligations, redemptions and
sinking and purchase fund requirements 48 78
Total $246 $310
Approximately 69% of total cash requirements (after payment of
dividends) was provided from internal sources in 1997 as compared
to 65% in 1996.
The Company's First and Refunding Mortgage Bond Indenture,
dated April 1, 1945 (Old Mortgage), contains provisions prohibiting
the issuance of additional bonds thereunder (Class A Bonds) unless
net earnings (as therein defined) for twelve consecutive months out
of the fifteen months prior to the month of issuance are at least
twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1997 the
Bond Ratio was 4.32. The issuance of additional Class A Bonds also
is restricted to an additional principal amount equal to (i) 60% of
unfunded net property additions (which unfunded net property
additions totaled approximately $579 million at December 31,
1997), (ii) retirements of Class A Bonds (which retirement credits
totaled $67.5 million at December 31, 1997), and (iii) cash on
deposit with the Trustee.
The Company has a bond indenture dated April 1, 1993 (New
Mortgage) covering substantially all of its electric properties
under which its future mortgage-backed debt (New Bonds) will be
issued. New Bonds are issued under the New Mortgage on the basis
of a like principal amount of Class A Bonds issued under the
Old Mortgage which have been deposited with the Trustee of
the New Mortgage (of which $185 million were available for such
purpose as of December 31, 1997), until such time as all presently
outstanding Class A Bonds are retired. Thereafter, New Bonds will
be issuable on the basis of property additions in a principal
amount equal to 70% of the original cost of electric and common
plant properties (compared to 60% of value for Class A Bonds under
the Old Mortgage), cash deposited with the Trustee, and retirement
of New Bonds. New Bonds will be issuable under the New Mortgage
only if adjusted net earnings (as therein defined) for twelve
consecutive months out of the eighteen months immediately preceding
the month of issuance are at least twice the annual interest
requirements on all outstanding bonds (including Class A Bonds) and
New Bonds to be outstanding (New Bond Ratio). For the year ended
December 31, 1997 the New Bond Ratio was 5.87.
On April 24, 1997, the Company sold $100 million of 6.52%
cumulative preferred stock, par value $100 per share. Proceeds
from the sale were used to reduce short-term indebtedness incurred
for the Company's construction program, to refinance senior
securities and for general corporate purposes.
On October 28, 1997 SCE&G Trust I (the "Trust"), a Delaware
statutory business trust and a subsidiary of the Company, issued
$50 million of 7.55% Trust Preferred Securities, Series A. The
Trust used the proceeds from the sale to purchase unsecured 7.55%
Junior Subordinated Debentures of the Company. The financial
statements of the Trust are consolidated with those of the Company.
Without the consent of at least a majority of the total voting
power of the Company's preferred stock, the Company may not issue
or assume any unsecured indebtedness if, after such issue or
assumption, the total principal amount of all such unsecured
indebtedness would exceed 10% of the aggregate principal amount of
all of the Company's secured indebtedness and capital and surplus;
however, no such consent is required to enter into agreements for
payment of principal, interest and premium for securities issued
for pollution control purposes.
Pursuant to Section 204 of the Federal Power Act, the Company
must obtain the FERC authority to issue short-term debt. The FERC
has authorized the Company to issue up to $250 million of unsecured
promissory notes or commercial paper with maturity dates of
twelve months or less, but not later than December 31, 1999.
26
At December 31, 1997 the Company had $315 million of
authorized lines of credit which includes a credit agreement for a
maximum of $250 million to support the issuance of commercial
paper. Unused lines of credit at December 31, 1997 totaled $315
million. The Company's commercial paper outstanding at December
31, 1997 and December 31, 1996 was $13.3 million and $90 million,
respectively. In addition, Fuel Company has a credit
agreement for a maximum of $125 million with the full amount
available at December 31, 1997. The credit agreement supports the
issuance of short-term commercial paper for the financing of
nuclear and fossil fuels and sulfur dioxide emission allowances.
Fuel Company commercial paper outstanding at December 31, 1997 was
$80.3 million,
The Company's Restated Articles of Incorporation prohibit
issuance of additional shares of preferred stock without consent of
the preferred stockholders unless net earnings (as defined therein)
for the twelve consecutive months immediately preceding the month
of issuance are at least one and one-half times the aggregate of
all interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1997 the
Preferred Stock Ratio was 2.69.
The Company anticipates that its 1998 cash requirements of
$389.6 million will be met through internally generated funds
(approximately 59%, after payment of dividends), the sales of
additional equity securities, additional equity contributions from
SCANA and the incurrence of additional short-term and long-term
indebtedness.
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.
Environmental Matters
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by the
year 2000. These requirements are being phased in over two
periods. The first phase had a compliance date of January 1, 1995
and the second, January 1, 2000. The Company's facilities did not
require modifications to meet the requirements of Phase I. The
Company will most likely meet the Phase II requirements through the
burning of natural gas and/or lower sulfur coal in its generating
units and the purchase and use of sulfur dioxide emission
allowances. Low nitrogen oxide burners are being installed to
reduce nitrogen oxide emissions to the levels required by Phase II.
Air toxicity regulations for the electric generating industry are
likely to be promulgated around the year 2000.
The Company filed with DHEC compliance plans related to Phase
II sulfur dioxide requirements in 1995, and Phase II nitrogen oxide
requirements in December, 1997. The Company currently estimates
that air emissions control equipment will require capital
expenditures of $90.3 million over the 1998-2002 period to
retrofit existing facilities, with increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2007, the Company
anticipates total capital expenditures of approximately $185
million.
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a national
permit program. Discharge permits have been issued for all and
renewed for nearly all of the Company's and GENCO's generating
units. Concurrent with renewal of these permits, the permitting
agency has implemented a more rigorous program in monitoring and
controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. The Company has been developing
compliance plans for these initiatives. Amendments to the Clean
Water Act proposed in Congress include several provisions which, if
passed, could prove costly to the Company. These include, but are
not limited to, limitations to mixing zones and the implementation
of technology-based standards.
The South Carolina Solid Waste Policy and Management Act of
1991 directed DHEC to promulgate regulations for the disposal of
industrial solid waste. DHEC has promulgated a proposed regulation
which, if adopted as a final regulation in its present form, would
significantly increase the Company's and GENCO's costs of
construction and operation of existing and future ash management
facilities.
27
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
an estimate is made of the amounts of expenditures, if any,
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, accrued and actually expended to
date for site assessments and cleanup relate primarily to
regulated operations; such amounts are deferred and are being
amortized and recovered through rates over a five-year period for
electric operations and an eight-year period for gas operations.
The Company has also recovered portions of its environmental
liabilities through settlements with various insurance carriers.
Deferred amounts, net of amounts recovered through rates and
insurance settlements, totaled $32.4 million and $41.4 million at
December 31, 1997 and 1996, respectively. The deferral includes
the estimated costs associated with the matters discussed below.
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 before cleanup is initiated.
The PRPs have agreed with the EPA to participate in an
innovative approach to site investigation and cleanup called
"Superfund Accelerated Cleanup Model," allowing the pre-
cleanup site investigation process to be compressed
significantly. The 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
conditionally approved a Remedial Investigation Report in March
1997. Although the Company is continuing to investigate cost-
effective clean-up methodologies, further work is pending EPA
approval of the final draft of the Remedial Investigation
Report.
In October 1996 the City of Charleston and the Company settled
all environmental claims the City may have had against the
Company involving the Calhoun Park area for a payment of $26
million over four years (1996 through 1999) by the Company to
the City. The Company is recovering the amount of the
settlement, which does not encompass site assessment and
cleanup costs, through rates in the same manner as other
amounts accrued for site assessments and cleanup as discussed
above. As part of the environmental settlement, the Company
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.
Construction is expected to begin in 1998. The total amount
of the bond is not to exceed $16.9 million, the maximum
expected project cost.
The Company owns three other decommissioned manufactured gas
plant sites which contain residues of by-product chemicals.
The Company is investigating the sites to monitor the nature
and extent of the residual contamination.
Regulatory Matters
On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which was
designed to produce additional revenues, based on a test year, of
approximately $67.5 million annually. The increase has been
implemented in two phases. The first phase, an increase in
revenues of approximately $59.5 million annually or 6.47%,
commenced in January 1996. The second phase, an increase in
revenues of approximately $8.0 million annually, based on a test
year, or .87%, was implemented in January 1997. The PSC
authorized a return on common equity of 12.0%. The PSC also
approved establishment of a Storm Damage Reserve Account capped at
$50 million to be collected through rates over a ten-year period.
Additionally, the PSC approved accelerated recovery of a
significant portion of the Company's electric regulatory assets
(excluding deferred income tax assets) and the remaining transition
obligation for postretirement benefits other than pensions,
changing the amortization periods to allow recovery by the end of
the year 2000. The Company's request to shift, for ratemaking
purposes, approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved. The Consumer Advocate appealed certain issues
in the order to the South Carolina Circuit Court, which affirmed
the PSC's decisions, and subsequently to the South Carolina Supreme
Court which is expected to hear the case and issue a ruling prior
to the end of 1998. While the outcome of this proceeding is
uncertain, the Company does not believe that
28
any significant adverse changes in the rate order is likely. The
PSC's order does not apply to wholesale electric revenues under the
FERC's jurisdiction, which constitute approximately two percent of
the Company's electric revenues. The FERC rejected the transfer of
depreciation reserves for rates subject to its jurisdiction.
The Company's regulated business operations were impacted by
the NEPA and FERC Orders No. 636 and 888. NEPA was designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. See "Competition" for a discussion of FERC
Order 888. Order No. 636 was intended to deregulate the markets
for interstate sales of natural gas by requiring that pipelines
provide transportation services that are equal in quality for all
gas suppliers whether the customer purchases gas from the pipeline
or another supplier. In the opinion of the Company, it continues
to be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any material
adverse impact on the results of operations, cash flows, financial
position or business prospects.
Other
The year 2000 issue could have a material impact on the
operations of the Company if required modifications and conversions
are not made to ensure that all system software is date code
compliant. The Company has formed a steering committee to direct
the resolution of this major issue. The steering committee, which
reports to the senior officers of the Company and to the board of
directors, is chaired by the chief financial officer of the Company
and is comprised of officers representing all operational areas.
Reporting to the committee are the technical personnel responsible
for the evaluation and remediation of system software.
The Company has evaluated the impact of the year 2000 on its
information systems applications and operating software and is
implementing a plan of remediation expected to be completed during
the first quarter of 1999. The present estimated cost of the plan
of remediation is not material to results of operations, financial
position or cash flows.
The Company also has begun evaluating embedded processors
located in field operations areas for the purpose of identifying
those that will have to be modified or replaced. The initial
inventory has been completed and impact assessment is expected to
be completed by mid-1998. At that time the Company will prepare
and implement a plan designed to complete all substantive required
modifications and replacements in time to prevent problems with
operational systems related to date codes. An estimate of the cost
of the required changes is not available.
In particular, with regard to the evaluation and remediation
of the year 2000 issue at the Company's Summer Station, the Company
is closely cooperating with other utility companies, including
utilities in the southeast, 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.
The Company is communicating with all of its significant
suppliers to determine the extent to which the Company is
vulnerable to those suppliers' failure to remediate their own year
2000 issue. The extent to which significant customers have
resolved the year 2000 issue, and the resulting impact on the
demand for the Company's products, is not determinable. There can
be no guarantee that the systems of other companies on which the
Company's systems rely will be timely converted. A failure to
convert by another company, or a conversion that is incompatible
with the Company's systems, could have material adverse effect on
the results of operations, financial position or cash flows of the
Company.
29
RESULTS OF OPERATIONS
Net Income
Net income and the percent increase (decrease) from the
previous year for the years 1997, 1996 and 1995 were as follows:
1997 1996 1995
(Millions of Dollars)
Net income $194.7 $190.5 $169.2
Percent increase (decrease) in net
income 2.19% 12.59% 11.27%
1997 Net income increased for the year primarily as a result
of increases in gas sales margins.
1996 Net income increased for the year primarily as a result
of increases in electric and gas sales margins which
more than offset increases in operating expenses.
The Company's financial statements include AFC. AFC is a
utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is
shown on the balance sheet as construction work in progress) is
capitalized. An equity portion of AFC is included in nonoperating
income and a debt portion of AFC is included in interest charges
(credits) as noncash items, both of which have the effect of
increasing reported net income. AFC represented approximately 4.0%
of income before income taxes in 1997, 3.2% in 1996 and 7.9% in
1995.
Electric Operations
Electric sales margins for 1997, 1996 and 1995 were as
follows:
1997 1996 1995
(Millions of Dollars)
Electric revenues $1,103.1 $1,106.7 $1,006.6
Less: Fuel used in electric generation 181.0 187.1 177.6
Purchased power 109.2 106.8 98.2
Margin $ 813.0 $ 812.8 $ 730.8
, 1997 The electric sales margin increased slightly due to the
favorable impact of the rate increase placed into
effect in January 1997 and economic growth factors
which were offset by the effect of milder weather.
, 1996 The electric sales margin increased primarily over the
prior year primarily as a result of the rate increase
received by the Company in January 1996 and economic
growth factors.
Increases (decreases) from the prior year in megawatt-hour
(MWH) sales volume by classes were as follows:
Classification 1997 1996
Residential (292,518) 212,888
Commercial 100,324 144,536
Industrial 113,717 110,147
Sales for Resale (excluding interchange) (538,005) (39,853)
Other 15 (1,013)
Total territorial (616,467) 426,705
Negotiated Market Sales Tariff 564,081 699,425
Total (52,386) 1,126,130
30
The electric sales volume for residential sales decreased for
1997 as a result of milder weather. The decrease in sales for
resale and the increase in sales under the Negotiated Market Sales
Tariff from 1996 to 1997 were the result of a municipality
terminating its wholesale power contract and transferring to a
negotiated market sales tariff.
Gas Operations
Gas sales margins for 1997, 1996 and 1995 were as follows:
1997 1996 1995
(Millions of Dollars)
Gas operating revenues $233.6 $234.8 $200.6
Less: Gas purchased for resale 151.9 157.1 125.0
Margin $ 81.7 $ 77.7 $ 75.6
, 1997 The gas sales margin increased over the prior year as a result of
higher margins and sales tointerruptible customers.
, 1996 The gas sales margin increased over the prior year as a result of
increased firm sales.
Increases (decreases) from the prior year in dekatherm (DT) sales volume
by classes, including transportation gas, were as follows:
Classification 1997 1996
Residential (2,188,215) 1,774,289
Commercial (123,385) 590,843
Industrial 1,820,166 441,571
Transportation gas (430,610) (495,256)
Total (922,044) 2,311,447
The gas sales volume decreased for 1997 as a result of milder
weather which was offset by increases in contract prices for
industrial interruptible customers.
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including
taxes, were as follows:
Classification 1997 1996
(Millions of Dollars)
Other operation and maintenance $ 3.0 $22.3
Depreciation and amortization 4.7 17.4
Income taxes (9.7) 10.8
Other taxes 8.1 3.2
Total $ 6.1 $53.7
, 1997 Other operation and maintenance expenses increased
somewhat from 1996 levels. A decrease in transit operating
costs resulting from the Company's
transfer of the ownership of the Charleston transit
system to the City of Charleston in October 1996 largely
offset increases in costs at electric generating plants
and other operating costs. The increase in depreciation
and amortization expenses for 1997 reflects the additions
to plant-in-service. The change in income tax expense
is primarily due to change in pre-tax operating income
and difference between estimated income taxes accrued and
actual income tax expense per the tax returns as filed.
The increase in other taxes results primarily from the
accrual of additional property taxes, beginning in
January 1997, related to the Cope plant and other
property additions which was partially offset by a
reduction in the 1997 property tax assessment. Recovery
of the Cope plant property taxes is provided for in a
retail electric rate increase that became effective
January 1997.
31
, 1996 Other operation and maintenance expenses increased
primarily as a result of higher production costs
attributable to the Cope plant which
became operational in January 1996. The increase in
depreciation and amortization expenses reflects the
addition of the Cope plant and other additions to plant-
in-service. The increase in income tax expense
corresponds to the increase in operating income. The
increase in other taxes reflects higher property taxes
resulting from property additions and higher millages and
assessments.
Interest Expense
Increases (decreases) in interest expense, excluding the debt
component of AFC, were as follows:
Classification 1997 1996
(Millions of Dollars)
Interest on long-term debt, net $(0.1) $(1.2)
Other interest expense 2.7 (2.0)
Total $ 2.6 $(3.2)
There was no material change in interest expense from 1996 to
1997. The decrease in interest expense from 1995 to 1996 was due
primarily to reductions in outstanding debt throughout most of the
year.
32
PAGE 33
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below
are held for purposes other than trading.
Interest rate risk - The table below provides information
about the Company's financial instruments that are sensitive to
changes in interest rates. For debt obligations, the table
presents principal cash flows and related weighted average interest
rates by expected maturity dates.
December 31, 1997
Expected Maturity Date
(Millions of Dollars)
There- Fair
Liabilities 1998 1999 2000 2001 2002 after Total Value
Long-Term Debt:
Fixed Rate ($) 47.7 27.8 201.5 21.3 51.3 1,052.0 1,371.6 1,384.7
Average Interest Rate 6.33 6.00 5.94 6.00 7.10 7.52 7.19
While a decrease in market interest rates would increase the
fair value of debt, it is unlikely that events which would result
in a realized loss will occur.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report....................................... 34
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1997 and 1996... 35
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1997, 1996 and 1995............. 37
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1996 and 1995............................. 38
Consolidated Statements of Capitalization as of
December 31, 1997 and 1996................................... 39
Notes to Consolidated Financial Statements..................... 41
Supplemental financial statement schedules are omitted because of the
absence of conditions under which they are required or because the required
information is included in the consolidated financial statements or in the notes
thereto.
33
INDEPENDENT AUDITORS' REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and
Statements of Capitalization of South Carolina Electric & Gas
Company (Company) as of December 31, 1997 and 1996 and the related
Consolidated Statements of Income and Retained Earnings and of Cash
Flows for each of the three years in the period ended December 31,
1997. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion
on the financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company at December 31, 1997 and 1996 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1997 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 9, 1998
34
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1997 1996
(Millions of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $4,020 $3,871
Gas 353 338
Other 84 86
Total 4,457 4,295
Less accumulated depreciation and amortization 1,421 1,332
Total 3,036 2,963
Construction work in progress 221 193
Nuclear fuel, net of accumulated amortization 53 41
Utility Plant, Net 3,310 3,197
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 17 12
Current Assets:
Cash and temporary cash investments (Note 8) 6 5
Receivables - customer and other 165 172
Inventories (At average cost):
Fuel (Notes 1, 3 and 4) 23 33
Materials and supplies 48 45
Prepayments 10 9
Deferred income taxes 21 20
Total Current Assets 273 284
Deferred Debits:
Emission allowances 31 31
Environmental 32 41
Nuclear plant decommissioning fund (Note 1) 49 42
Pension asset, net (Note 1) 82 58
Other (Note 1) 260 294
Total Deferred Debits 454 466
Total $4,054 $3,959
35
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1997 1996
(Millions of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment:
Common equity (Note 5) $1,447 $1,413
Preferred stock (Not subject to purchase or sinking funds) 106 26
Total Stockholders' Investment 1,553 1,439
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 12 43
Company - Obligated Mandatorily Redeemable Preferred
Securities of the Company's Subsidiary Trust, SCE&G Trust I
holding solely $50 million, principal amount of 7.55%
of Junior Subordinated Debentures of the Company, due 2027 50 -
Long-Term Debt, Net (Notes 3, 4 and 8) 1,262 1,277
Total Capitalization 2,877 2,759
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 13 90
Current portion of long-term debt (Note 3) 48 43
Accounts payable 53 67
Accounts payable - affiliated companies (Notes 1 and 3) 32 32
Customer deposits 16 15
Taxes accrued 45 67
Interest accrued 22 21
Dividends declared 58 36
Other 7 7
Total Current Liabilities 294 378
Deferred Credits:
Deferred income taxes (Notes 1 and 7) 539 522
Deferred investment tax credits (Notes 1 and 7) 89 75
Reserve for nuclear plant decommissioning (Note 1) 49 42
Postretirement benefits 61 37
Other (Note 1) 145 146
Total Deferred Credits 883 822
Commitments and Contingencies (Note 10) - -
Total $4,054 $3,959
See Notes to Consolidated Financial Statements.
36
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1997 1996 1995
(Millions of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $1,103 $1,107 $1,006
Gas 234 235 201
Transit 1 3 4
Total Operating Revenues 1,338 1,345 1,211
Operating Expenses:
Fuel used in electric generation 181 187 178
Purchased power (including affiliated
purchases)(Note 1) 109 107 98
Gas purchased from affiliate for resale (Note 1) 152 157 125
Other operation 222 222 211
Maintenance 67 64 53
Depreciation and amortization (Note 1) 140 135 118
Income taxes (Notes 1 and 7) 98 108 97
Other taxes 87 79 75
Total Operating Expenses 1,056 1,059 955
Operating Income 282 286 256
Other Income (Note 1):
Allowance for equity funds used during construction 6 4 9
Other income (loss), net of income taxes 3 - -
Total Other Income 9 4 9
Income Before Interest Charges 291 290 265
Interest Charges (Credits):
Interest on long-term debt, net 96 97 98
Other interest expense (Notes 1 and 3) 5 7 9
Allowance for borrowed funds used
during construction (Note 1) (6) (5) (11)
Total Interest Charges, Net 95 99 96
Income Before Preferred Dividend Requirements on
Mandatorily Redeemable Preferred Securities 196 191 169
Preferred Dividend Requirement of
Company - Obligated Mandatorily Redeemable
Preferred Securities. 1 - -
Net Income 195 191 169
Preferred Stock Cash Dividends (At stated rates) (9) (6) (6)
Earnings Available for Common Stock 186 185 163
Retained Earnings at Beginning of Year 415 366 324
Common Stock Cash Dividends Declared (Note 5) (163) (136) (121)
Retained Earnings at End of Year $ 438 $ 415 $ 366
See Notes to Consolidated Financial Statements.
37
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1997 1996 1995
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $ 195 $ 190 $ 169
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 140 135 118
Amortization of nuclear fuel 19 19 20
Deferred income taxes, net 16 32 (18)
Pension asset (24) (23) (15)
Postretirement benefits 24 16 8
Allowance for funds used during construction (12) (9) (21)
Over (under) collections, fuel adjustment clause - (8) 19
Changes in certain current assets and liabilities:
(Increase) decrease in receivables 6 (10) (16)
(Increase) decrease in inventories 8 1 (5)
Increase (decrease) in accounts payable (13) - 3
Increase (decrease) in taxes accrued (22) 3 17
Other, net 31 (19) (25)
Net Cash Provided From Operating Activities 368 327 254
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, net of AFC (232) (209) (273)
(Increase) decrease in nonutility property and investments (5) - -
Net Cash Used For Investing Activities (237) (209) (273)
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds and other long-term debt 1 - 103
Issuance of company - obligated mandatorily
redeemable trust preferred securities 49 - -
Equity contributions from parent 12 49 140
Issuance of preferred stock 99 - -
Repayments:
Notes payable - affiliated company - - (19)
Mortgage bonds and other long-term debt (15) (23) (78)
Preferred stock (53) (3) (3)
Repayment of Bank Loans (10) (3) -
Dividend Payments:
Common stock (141) (133) (117)
Preferred stock (9) (5) (6)
Short-term borrowings, net (77) 10 (20)
Fuel and emission allowance financings, net 14 (11) 26
Net Cash Provided From Financing Activities (130) (119) 26
Net Increase (Decrease) in Cash and Temporary Cash Investments 1 (1) 7
Cash and Temporary Cash Investments, January 1 5 6 -
Cash and Temporary Cash Investments, December 31 $ 6 $ 5 $ 7
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $6, $5 and $11) $ 100 $ 103 $ 106
- Income taxes (48) 102 96
Noncash Financing Activities:
Charleston Franchise Agreement - 21 -
Charleston Environmental Agreement - 20 -
See Notes to Consolidated Financial Statements.
38
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1997 1996
Common Equity (Note 5): (Millions of Dollars)
Common stock, 4.50 par value, authorized 50,000,000 shares; issued
and outstanding, 40,296,147 shares $ 181 $ 181
Premium on common stock 395 395
Other paid-in capital 438 427
Capital stock expense (5) (5)
Retained earnings 438 415
Total Common Equity 1,447 50% 1,413 51%
Cumulative Preferred Stock (Not subject to purchase or sinking funds):
$100 Par Value - Authorized 1,200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1997 1996 Current Through Minimum
$100 Par 6.52% 1,000,000 - 100.00 - 100.00 100 -
$100 Par 8.40% - 197,668 101.00 - 101.00 - 20
$50 Par 5.00% 125,209 125,209 52.50 - 52.50 6 6
Total Preferred Stock (Not subject to purchase or sinking funds) 106 4% 26 1%
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8):
$100 Par Value - Authorized 1,550,000 shares
Shares Outstanding Redemption Price
Eventual
Series 1997 1996 Current Through Minimum
7.70% - 84,000 101.00 - 101.00 - 8
8.12% - 118,812 102.03 - 102.03 - 12
Total 202,812 202,812
$50 Par Value - Authorized 1,591,094 shares
Shares Outstanding Redemption Price
Eventual
Series 1997 1996 Current Through Minimum
4.50% 14,400 16,000 51.00 - 51.00 1 1
4.60% - 87 50.50 - 50.50 - -
4.60%(A) 21,894 24,052 51.00 - 51.00 1 1
4.60%(B) 70,000 71,400 50.50 - 50.50 4 4
5.125% 68,000 71,000 51.00 - 51.00 3 3
6.00% 76,800 80,000 50.50 - 50.50 4 4
8.72% - 64,000 51.00 12-31-98 50.00 - 3
9.40% - 176,751 51.175 - 51.175 - 9
Total 251,094 503,290
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1997 and 1996
Total Preferred Stock (Subject to purchase or sinking funds) 13 45
Less: Current portion, including sinking fund requirements 1 2
Total Preferred Stock, Net (Subject to purchase or sinking funds) 12 - 43 2%
Company - Obligated Mandatorily Redeemable Preferred
Securities of the Company's Subsidiary Trust, SCE&G Trust I,
holding solely $50 million principal amount of 7.55% of
Junior Subordinated Debentures of the Company, due 2027. 50 2% - -
39
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1997 1996
(Millions of Dollars)
Long-Term Debt (Notes 3, 4 and 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100 100
6 1/4% 2003 100 100
7.70% 2004 100 100
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
First and Refunding Mortgage Bonds:
Year of
Series Maturity
6% 1997 - 15
6 1/2% 1998 20 20
7 1/4% 2002 30 30
9% 2006 131 131
8 7/8% 2021 114 114
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984, due 2014 (6.50%) 57 57
Orangeburg County Series 1994 due 2024 (5.70%) 30 30
Other 16 10
Commercial Paper 80 66
Charleston Franchise Agreement due 1997-2002 18 22
Charleston Environmental Agreement due 1997-1999 13 20
Other 4 1
Total Long-Term Debt 1,313 1,323
Less: Current maturities, including sinking fund requirements 48 43
Unamortized discount 3 3
Total Long-Term Debt, Net 1,262 44% 1,277 46%
Total Capitalization $2,877 100% $2,759 100%
See Notes to Consolidated Financial Statements.
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
The Company, a public utility, is a South Carolina
corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation (SCANA), a South Carolina holding company. The
Company is engaged predominately in the generation and sale of
electricity to wholesale and retail customers in South Carolina
and in the purchase, sale and transportation of natural gas to
retail customers in South Carolina.
The accompanying Consolidated Financial Statements include
the accounts of the Company, South Carolina Fuel Company, Inc.
(Fuel Company) and SCE&G Trust I. (See Note 1N.) Intercompany
balances and transactions between the Company, Fuel Company and
SCE&G Trust I have been eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain
affiliates to purchase gas for resale to its distribution
customers and to purchase electric energy. The Company purchases
all of its natural gas requirements from Pipeline Corporation and
at December 31, 1997 and 1996 the Company had approximately $22.1
million and $22.3 million, respectively, payable to Pipeline
Corporation for such gas purchases. The Company purchases all of
the electric generation of Williams Station, which is owned by
GENCO, under a unit power sales agreement. At December 31, 1997
and 1996 the Company had approximately $9.1 million and $8.6
million, respectively, payable to GENCO for unit power purchases.
Such unit power purchases, which are included in "Purchased
power," amounted to approximately $99.8 million, $95.3 million
and $83.5 million in 1997, 1996 and 1995, respectively.
Total interest income, based on market interest rates,
associated with the Company's advances to affiliated companies
was approximately $20,000, $36,000 and $174,000 in 1997, 1996
and 1995, respectively.
In 1997 and 1996 there were no amounts relating to advances
from affiliated companies included in "Other interest expense";
however, for 1995 $114,000 was included. Intercompany interest
is calculated at market rates.
B. Basis of Accounting
The Company accounts for its regulated utility operations,
assets and liabilities in accordance with the provisions of
Statements 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 December 31, 1997, approximately $236 million and $62
million of regulatory assets and liabilities, respectively,
including amounts recorded for deferred income tax assets and
liabilities of approximately $118 million and $52 million,
respectively. The electric and gas regulatory assets of
approximately $71 million and $44 million, respectively
(excluding deferred income tax assets) are being recovered
through rates and, as discussed in Note 2A, the Public Service
Commission of South Carolina (PSC) has approved accelerated
recovery of approximately $45 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 would
be required to write off its regulatory assets and liabilities.
Such an event could have a material adverse effect on the
Company's results of operations in the period the write-off is
recorded, but it is not expected that cash flows or financial
position would be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in
accordance with the Uniform System of Accounts prescribed by the
Federal Energy Regulatory Commission (FERC) and as adopted by the
PSC.
41
D. Utility Plant
Utility plant is stated substantially at original cost. The
costs of additions, renewals and betterments to utility plant,
including direct labor, material and indirect charges for
engineering, supervision and an allowance for funds used during
construction, are added to utility plant accounts. The original
cost of utility property retired or otherwise disposed of is
removed from utility plant accounts and generally charged, along
with the cost of removal, less salvage, to accumulated
depreciation. The costs of repairs, replacements and renewals of
items of property determined to be less than a unit of property
are charged to maintenance expense.
The Company, operator of the V. C. Summer Nuclear Station
(Summer Station), and the South Carolina Public Service Authority
(PSA) are joint owners of Summer Station in the proportions of
two-thirds and one-third, respectively. The parties share the
operating costs and energy output of the plant in these
proportions. Each party, however, provides its own financing.
Plant-in-service related to the Company's portion of Summer
Station was approximately $978.2 million and $937.2 million as of
December 31, 1997 and 1996, respectively. Accumulated
depreciation associated with the Company's share of Summer
Station was approximately $323.6 million and $313.2 million as of
December 31, 1997 and 1996, respectively. The Company's share of
the direct expenses associated with operating Summer Station is
included in "Other operation" and "Maintenance" expenses.
E. Allowance for Funds Used During Construction
AFC, a noncash item, reflects the period cost of capital
devoted to plant under construction. This accounting practice
results in the inclusion of, as a component of construction cost,
the costs of debt and equity capital dedicated to construction
investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates
for utility services. The Company has calculated AFC using
composite rates of 8.8%, 8.1% and 8.6% for 1997, 1996 and 1995,
respectively. These rates do not exceed the maximum allowable
rate as calculated under FERC Order No. 561. Interest on nuclear
fuel in process and sulfur dioxide emission allowances is
capitalized at the actual interest amount.
F. Revenue Recognition
Customers' meters are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the
accounting period in which the meters are read.
Fuel costs for electric generation are collected through the
fuel cost component in retail electric rates. The fuel cost
component contained in electric rates is established by the PSC
during annual fuel cost hearings. Any difference between actual
fuel costs and that contained in the fuel cost component is
deferred and included when determining the fuel cost component
during the next annual fuel cost hearing. The Company had
undercollected through the electric fuel cost component
approximately $1.3 million and at December 31, 1997 and
overcollected approximately $ 1.9 million December 31, 1996
which are included in "Deferred Debits - Other" and "Deferred
Credits - Other," respectively.
42
Customers subject to the gas cost adjustment clause are
billed based on a fixed cost of gas determined by the PSC during
annual gas cost recovery hearings. Any difference between actual
gas cost and that contained in the rates is deferred and included
when establishing gas costs during the next annual gas cost
recovery hearing. At December 31, 1997 and 1996 the Company had
undercollected through the gas cost recovery procedure
approximately $7.6 million and $10.9 million, respectively,
which are included in "Deferred Debits - Other."
The Company's gas rate schedules for residential, small
commercial and small industrial customers include a weather
normalization adjustment, which minimizes fluctuations in gas
revenues due to abnormal weather conditions.
G. Depreciation and Amortization
Provisions for depreciation are recorded using the straight-
line method for financial reporting purposes and are based on the
estimated service lives of the various classes of property. The
composite weighted average depreciation rates were 3.09%, 3.13%
and 3.02% for 1997, 1996 and 1995, respectively.
Nuclear fuel amortization, which is included in "Fuel used
in electric generation" and is recovered through the fuel cost
component of the Company's rates, is recorded using the units-of-
production method. Provisions for amortization of nuclear fuel
include amounts necessary to satisfy obligations to the
Department Of Energy (DOE) under a contract for disposal of spent
nuclear fuel.
The acquisition adjustment relating to the purchase of
certain gas properties in 1982 is being amortized over a 40-year
period using the straight-line method.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently scheduled to
commence when the operating license expires in the year 2022.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning cost
is referred to as COMReP (Cost of Money Reduction Plan). Under
this plan, funds collected through rates ($3.2 million in 1997
and 1996) are used to pay premiums on insurance policies on the
lives of certain Company personnel. The Company is the
beneficiary of these policies. Through these insurance
contracts, the Company is able to take advantage of income tax
benefits and accrue earnings on the fund on a tax-deferred basis
at a rate higher than can be achieved using more traditional
funding approaches. Amounts for decommissioning collected
through electric rates, insurance proceeds, and interest on
proceeds less expenses are transferred by the Company to an
external trust fund in compliance with the financial assurance
requirements of the Nuclear Regulatory Commission. Management
intends for the fund, including earnings thereon, to provide for
all eventual decommissioning expenditures on an after-tax basis.
The trust's sources of decommissioning funds under the COMReP
program include investment components of life insurance policy
proceeds, return on investment and the cash transfers from the
Company described above. The Company records its liability for
decommissioning costs in deferred credits.
43
Pursuant to the National Energy Policy Act passed by
Congress in 1992 and the requirements of the DOE, the Company has
recorded a liability for its estimated share of the DOE's
decontamination and decommissioning obligation. The liability,
approximately $4.0 million at December 31, 1997, has been
included in "Long-Term Debt, Net." The Company is recovering the
cost associated with this liability through the fuel cost
component of its rates; accordingly, this amount has been
deferred and is included in "Deferred Debits - Other."
I. Income Taxes
Deferred tax assets and liabilities are recorded for the tax
effects of temporary differences between the book basis and tax
basis of assets and liabilities at currently enacted tax rates.
Deferred tax assets and liabilities are adjusted for changes in
such rates through charges or credits to regulatory assets or
liabilities if they are expected to be recovered from, or passed
through to, customers; otherwise, they are charged or credited to
income tax expense.
J. Pension Expense
The Company participates in SCANA's noncontributory defined
benefit pension plan, which covers all permanent employees.
Benefits are based on years of accredited service and the
employee's average annual base earnings received during the last
three years of employment. SCANA's policy has been to fund the
plan to the extent permitted by the applicable Federal income tax
regulations as determined by an independent actuary.
Net periodic pension cost for the years ended December 31,
1997, 1996 and 1995 included the following components:
1997 1996 1995
(Millions of Dollars)
Service cost--benefits earned during the period $ 6.8 $ 6.5 $ 5.2
Interest cost on projected benefit obligation 23.5 22.0 19.5
Adjustments:
Return on plan assets (119.5) (78.6) (103.9)
Net amortization and deferral 72.8 40.1 74.8
Amounts contributed by the Company's
affiliates (0.6) (0.3) (0.2)
Net periodic pension (income) expense $(17.0) $(10.3) $ (4.6)
The determination of net periodic pension cost is based upon
the following assumptions:
1997 1996 1995
Annual discount rate 7.5% 7.5% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 3.0% 3.0% 2.5%
44
The following table sets forth the funded status of the plan
at December 31, 1997 and 1996:
1997 1996
(Millions of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $259.7 $243.9
Nonvested benefit obligation 25.4 23.7
Accumulated benefit obligation $285.1 $267.6
Plan assets at fair value
(invested primarily in equity and debt securities) $632.9 $523.5
Projected benefit obligation 344.4 306.9
Plan assets greater than
projected benefit obligation 288.5 216.6
Unrecognized net transition liability 7.4 8.2
Unrecognized prior service costs 13.4 8.2
Unrecognized net gain (227.1) (175.1)
Pension asset recognized in
Consolidated Balance Sheets $ 82.2 $ 57.9
The accumulated benefit obligation is based on the plan's
benefit formulas without considering expected future salary
increases. The following table sets forth the assumptions used
in determining the amounts shown above for the years 1997 and
1996.
1997 1996
Annual discount rate used to determine
benefit obligations 7.5% 7.5%
Assumed annual rate of future salary increases
for projected benefit obligation 4.0% 3.0%
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active and
retired employees. The costs of postretirement benefits other
than pensions are accrued during the years the employees render
the service necessary to be eligible for the applicable benefits.
The Company expensed approximately $8.1 million, $9.8 million
and $8.5 million, net of payments to current retirees, for the
years ended December 31, 1997, 1996 and 1995, respectively.
Additionally, to accelerate the amortization of the remaining
transition obligation for postretirement benefits other than
pensions, as authorized by the PSC, the Company expensed
approximately $15.6 million and $6.2 million for the years ended
December 31, 1997 and 1996, respectively. (See Note 2A.)
Net periodic postretirement benefit cost for the years ended
December 31, 1997, 1996 and 1995, included the following
components:
1997 1996 1995
(Millions of Dollars)
Service cost--benefits earned during the period $ 2.5 $ 2.6 $ 2.1
Interest cost on accumulated postretirement
benefit obligation 7.8 7.8 7.2
Adjustments:
Return on plan assets - - -
Amortization of unrecognized
transition obligation 18.9 9.5 3.3
Other net amortization and deferral 0.8 1.2 0.7
Amounts contributed by the Company's affiliates (1.1) (0.7) (0.6)
Net periodic postretirement benefit cost $28.9 $20.4 $12.7
45
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1997 1996 1995
Annual discount rate 7.5% 7.5% 8.0%
Health care cost trend rate 9.0% 9.5% 11.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 5.5% 5.5% 6.0%
The following table sets forth the funded status of the plan at
December 31, 1997 and 1996:
1997 1996
(Millions of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 76.7 $ 74.2
Other fully eligible participants 5.9 6.6
Other active participants 26.2 29.3
Accumulated postretirement benefit obligation 108.8 110.1
Plan assets at fair value - -
Accumulated postretirement benefit obligation 108.8 110.1
Plan assets less than accumulated postretirement
benefit obligation (108.8) (110.1)
Unrecognized net transition liability 29.8 48.7
Unrecognized prior service costs 5.8 6.2
Unrecognized net loss 12.2 17.8
Postretirement benefit liability recognized
in Consolidated Balance Sheets $ (61.0) $ (37.4)
The accumulated postretirement benefit obligation is based
upon the plan's benefit provisions and the following assumptions:
1997 1996
Assumed health care cost trend rate used to
measure expected costs 9.0% 9.5%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.5% 5.5%
Annual discount rate 7.5% 7.5%
Annual rate of salary increases 4.0% 3.0%
The effect of a one percentage-point increase in the assumed
health care cost trend rate for each future year on the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for the year ended December 31,
1997 and the accumulated postretirement benefit obligation as of
December 31, 1997 would be to increase such amounts by $0.2
million and $3.2 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on
Reacquired Debt
For regulatory purposes, long-term debt premium, discount
and expense are being amortized as components of "Interest on
long-term debt, net" over the terms of the respective debt
issues. Gains or losses on reacquired debt that is refinanced
are deferred and amortized over the term of the replacement debt.
46
L. Environmental
The Company has an environmental assessment program to
identify and assess current and former operating sites that could
require environmental cleanup. As site assessments are initiated
an estimate is made of the amount of expenditures, if any,
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, accrued and actually
expended to date for site assessments and cleanup relate
primarily to regulated operations; such amounts are deferred and
are being amortized and recovered through rates over a five-year
period for electric operations and an eight-year period for gas
operations. The Company has also recovered portions of its
environmental liabilities through settlements with various
insurance carriers. Deferred amounts, net of amounts recovered
through rates and insurance settlements, totaled $32.4 million
and $41.4 million at December 31, 1997 and 1996, respectively.
The deferral includes the estimated costs to be associated with
the matters discussed in Note 10C.
M. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide
emission allowances are purchased and financed by Fuel Company
under a contract which requires the Company to reimburse Fuel
Company for all costs and expenses relating to the ownership and
financing of fuel inventories and sulfur dioxide emission
allowances. Accordingly, such fuel inventories and emission
allowances and fuel-related assets and liabilities are included
in the Company's consolidated financial statements. (See Note 4.)
N. Temporary Cash Investments
The Company considers temporary cash investments having
original maturities of three months or less to be cash
equivalents. Temporary cash investments are generally in the
form of commercial paper, certificates of deposit and repurchase
agreements.
O. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1997 presentation.
P. Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
47
2. RATE MATTERS:
A. On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which was
designed to produce additional revenues, based on a test year,
of approximately $67.5 million annually. The increase has been
implemented in two phases. The first phase, an increase in
revenues of approximately $59.5 million annually or 6.47%,
commenced in January 1996. The second phase, an increase in
revenues of approximately $8.0 million annually, or .87%, was
implemented in January 1997. The PSC authorized a return on
common equity of 12.0%. The PSC also approved establishment of a
Storm Damage Reserve Account capped at $50 million to be
collected through rates over a ten-year period. Additionally,
the PSC approved accelerated recovery of a significant portion of
the Company's electric regulatory assets (excluding deferred
income tax assets) and the remaining transition obligation for
postretirement benefits other than pensions, changing the
amortization periods to allow recovery by the end of the year
2000. The Company's request to shift, for ratemaking purposes,
approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved. The Consumer Advocate appealed certain issues
in the order to the South Carolina Circuit Court, which affirmed
the PSC's decisions, and subsequently to the South Carolina
Supreme Court which is expected to hear the case and issue a
ruling prior to the end of 1998. While the outcome of this
proceeding is uncertain, the Company does not believe that any
significant adverse changes in the rate order is likely. The
PSC's order does not apply to wholesale electric revenues under
the FERC's jurisdiction, which constitute approximately two
percent of the Company's electric revenues. The FERC rejected
the transfer of depreciation reserves for rates subject to its
jurisdiction.
B. In 1994 the PSC issued an order approving the Company's
request to recover through a billing surcharge to its gas
customers the costs of environmental cleanup at the sites of
former manufactured gas plants. The billing surcharge is subject
to annual review and provides for the recovery of substantially
all actual and projected site assessment and cleanup costs and
environmental claims settlements for the Company's gas operations
that had previously been deferred. In October 1997, as a result
of the annual review, the PSC approved the Company's request to
increase the billing surcharge from $.006 per therm to $.011 per
therm which should enable the Company to recover the remaining
balance of $29.6 million by December 2002.
C. In September 1992 the PSC issued an order granting the
Company a $.25 increase in transit fares from $.50 to $.75 in
both Columbia and Charleston, South Carolina; however, the PSC
also required $.40 fares for low income customers and denied the
Company's request to reduce the number of routes and frequency of
service. The new rates were placed into effect in October 1992.
The Company appealed the PSC's order to the Circuit Court, which
in May 1995 ordered the case back to the PSC for reconsideration
of several issues including the low income rider program, routing
changes, and the $.75 fare. The Supreme Court declined to review
an appeal of the Circuit Court decision and dismissed the case.
The PSC and other intervenors filed another Petition for
Reconsideration, which the Supreme Court denied. The PSC and
other intervenors filed another appeal to the Circuit Court which
the Circuit Court denied in an order dated May 9, 1996. In this
order, the Circuit Court upheld its previous orders and remanded
them to the PSC. During August 1996, the PSC heard oral
arguments on the orders on remand from the Circuit Court. On
September 30, 1996, the PSC issued an order affirming its
previous orders and denied the Company's request for
reconsideration. The Company has appealed these two PSC orders
to the Circuit Court where they are awaiting action.
48
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including
amounts due under nuclear and fossil fuel agreements (see Note
4), and sinking fund requirements for the years 1998 through 2002
are summarized as follows:
Year Amount Year Amount
(Millions of Dollars)
1998 $ 47.7 2001 $ 21.3
1999 27.8 2002 51.3
2000 201.5
Approximately $17.2 million of the portion of long-term debt
payable in 1998 may be satisfied by either deposit and
cancellation of bonds issued upon the basis of property additions
or bond retirement credits, or by deposit of cash with the
Trustee.
On August 7, 1996 the City of Charleston executed 30-year
electric and gas franchise agreements with the Company. In
consideration for the electric franchise agreement, the Company
is paying the City $25 million over seven years (1996 through
2002) and has donated to the City the existing transit assets in
Charleston. The $25 million is included in electric plant-in-
service. In settlement of environmental claims the City may have
had against the Company involving the Calhoun Park area, where
the Company and its predecessor companies operated a manufactured
gas plant until the 1960's, the Company is paying the City $26
million over a four-year period (1996 through 1999). Such amount
is deferred (see Note 1L). The unpaid balances of these amounts
are included in "Long-Term Debt."
The Company has three-year revolving lines of credit
totaling $75 million, in addition to other lines of credit, that
provide liquidity for issuance of commercial paper. The three-
year lines of credit provide back-up liquidity when commercial
paper outstanding is in excess of $175 million. The long-term
nature of the lines of credit allow commercial paper in excess of
$175 million to be classified as long-term debt. The Company had
outstanding commercial paper of $13.3 million and $90 million at
December 31, 1997 and 1996, at weighted average interest rates of
5.90% and 5.53%, respectively.
Substantially all utility plant and fuel inventories are
pledged as collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories and sulfur dioxide
emission allowances are financed through the issuance by Fuel
Company of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires December 19, 2000. Accordingly, the
amounts outstanding have been included in long-term debt. The
credit agreement provides for a maximum amount of $125 million
that may be outstanding at any time.
Commercial paper outstanding totaled $80.3 million and $66.1
million at December 31, 1997 and 1996 at weighted average
interest rates of 5.87% and 5.62%, respectively.
49
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including
Preferred Stock Not Subject to Purchase or Sinking Funds) during
1997, 1996 and 1995 are summarized as follows:
Common Preferred Millions
Shares Shares of Dollars
Balance December 31, 1994 40,296,147 322,877 $1,159.5
Changes in Retained Earnings:
Net Income 169.2
Cash Dividends Declared:
Preferred Stock (at stated rates) (5.7)
Common Stock (121.4)
Equity Contributions from Parent 139.5
Balance December 31, 1995 40,296,147 322,877 1,341.1
Changes in Retained Earnings:
Net Income 190.5
Cash Dividends Declared:
Preferred Stock (at stated rates) (5.4)
Common Stock (135.8)
Equity Contributions from Parent
including transfer of assets 49.1
Balance December 31, 1996 40,296,147 322,877 1,439.5
Changes in Retained Earnings:
Net Income 194.6
Cash Dividends Declared:
Preferred Stock (at stated rates) (9.3)
Common Stock (162.6)
Equity Contributions from Parent 12.1
Issuance of Preferred Stock 1,000,000 100.0
Redemption of Preferred Stock (197,668) (19.8)
Changes in Capital Stock Expense 0.1
Changes in Loss on Resale of
Reacquired Stock (1.6)
Balance December 31, 1997 40,296,147 1,125,209 $1,553.0
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 common stock. In addition, with
respect to hydroelectric projects, the Federal Power Act requires
the appropriation of a portion of the earnings therefrom. At
December 31, 1997 approximately $21.5 million of retained
earnings were restricted by this requirement as to payment of
cash dividends on common stock.
6. PREFERRED STOCK:
The call premium of the respective series of preferred stock
in no case exceeds the amount of the annual dividend.
Retirements under sinking fund requirements are at par values.
The aggregate annual amount of purchase fund or sinking fund
requirements for preferred stock for the years 1998 through 2002
is $0.6 million.
50
The changes in "Total Preferred Stock (Subject to Purchase
or Sinking Funds)" during 1997, 1996 and 1995 are summarized as
follows:
Number Millions
of Shares of Dollars
Balance December 31, 1994 822,094 $ 51.9
Shares Redeemed:
$100 par value (6,809) (0.7)
$50 par value (51,666) (2.5)
Balance December 31, 1995 763,619 48.7
Shares Redeemed:
$100 par value (7,198) (0.7)
$50 par value (50,319) (2.6)
Balance December 31, 1996 706,102 45.4
Shares Redeemed:
$100 par value (202,812) (20.3)
$50 par value (252,196) (12.6)
Balance December 31, 1997 251,094 $ 12.5
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly-
owned subsidiary of the Company, issued $50 million (2,000,000
shares) of 7.55% Trust Preferred Securities, Series A (the
"Preferred Securities"). The Company owns all of the Common
Securities of the Trust (the "Common Securities"). The Preferred
Securities and the Common Securities (the "Trust Securities")
represent undivided beneficial ownership interests in the assets
of the Trust. The Trust exists for the sole purpose of issuing
the Trust Securities and using the proceeds thereof to purchase
from the Company its 7.55% Junior Subordinated Debentures due
September 30, 2027. The sole asset of the Trust is $50 million
of Junior Subordinated Debentures of the Company. Accordingly,
no financial statements of the Trust are presented. The
Company's obligations under the Guarantee Agreement entered into
in connection with the Preferred Securities, when taken together
with the Company's obligation to make interest and other payments
on the Junior Subordinated Debentures issued to the Trust and the
Company's obligations under its Indenture pursuant to which the
Junior Subordinated Debentures are issued, provides a full and
unconditional guarantee by the Company of the Trust's obligations
under the Preferred Securities. Proceeds were used to redeem
preferred stock of the Company.
The preferred securities of the Trust are redeemable only in
conjunction with the redemption of the related 7.55% Junior
Subordinated Debentures. The Junior Subordinated Debentures will
mature on September 30, 2027 and may be redeemed, in whole or in
part, at any time on or after September 30, 2002 or upon the
occurrence of a Tax Event. A Tax Event occurs if an opinion is
received from counsel experienced in such matters that there is
more than an insubstantial risk that: (1) the Trust is or will
be subject to Federal income tax, with respect to income received
or accrued on the Junior Subordinated Debentures, (2) interest
payable by the Company on the Junior Subordinated Debentures will
not be deductible, in whole or in part, by the Company for
Federal income tax purposes, and (3) the Trust will be subject to
more than a de minimis amount of other taxes, duties, or other
governmental charges.
Upon the redemption of the Junior Subordinated Debentures,
payment will simultaneously be applied to redeem Preferred
Securities having an aggregate liquidation amount equal to the
aggregate principal amount of the Junior Subordinated Debentures.
The Preferred Securities are redeemable at $25 per preferred
security plus accrued distributions.
51
7. INCOME TAXES:
Total income tax expense for 1997, 1996 and 1995 is as follows:
1997 1996 1995
(Millions of Dollars)
Current taxes:
Federal $ 88.0 $ 88.2 $ 94.1
State (6.9) 13.1 14.3
Total current taxes 81.1 101.3 108.4
Deferred taxes, net:
Federal 3.7 8.3 (7.3)
State 1.5 1.8 (0.6)
Total deferred taxes 5.2 10.1 (7.9)
Investment tax credits:
Deferred - State 19.0 - -
Amortization of amounts
deferred-State (1.5) - -
Amortization of amounts
deferred-Federal (3.2) (3.2) (3.2)
Total Investment Tax credit 14.3 (3.2) (3.2)
Total income tax expense $100.6 $108.2 $ 97.3
The difference in total income tax expense and the amount
calculated from the application of the statutory Federal income
tax rate (35% for 1997, 1996 and 1995) to pre-tax income is
reconciled as follows:
1997 1996 1995
(Millions of Dollars)
Net income $194.7 $190.5 $169.2
Total income tax expense:
Charged to operating expenses 98.1 107.7 97.0
Charged (credited) to other items 2.5 0.5 0.3
Total pre-tax income $295.3 $298.7 $266.5
Income taxes on above at statutory
Federal income tax rate $103.4 $104.5 $ 93.3
Increases (decreases) attributable to:
State income taxes (less Federal
income tax effect) 7.9 9.7 8.9
Deferred income tax reversal at
higher than statutory rates (3.5) (3.4) (3.3)
Amortization of Federal
investment tax credits (3.2) (3.2) (3.2)
Allowance for equity funds
used during construction (2.1) (1.4) (3.3)
Other differences, net (1.9) 2.0 4.9
Total income tax expense $100.6 $108.2 $ 97.3
52
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $518.5
million at December 31, 1997 and $501.7 million at December 31,
1996 are as follows:
1997 1996
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 55.4 $ 46.5
Cycle billing 20.5 19.8
Nuclear operations expenses 3.1 4.7
Deferred compensation 6.7 6.6
Other postretirement benefits 14.6 10.8
Other 8.1 6.6
Total deferred tax assets 108.4 95.0
Deferred tax liabilities:
Property plant and equipment 561.2 540.9
Pension expense 27.5 21.8
Reacquired debt 7.5 8.3
Research and experimentation 19.5 12.5
Deferred fuel 3.6 3.7
Other 7.6 9.5
Total deferred tax liabilities 626.9 596.7
Net deferred tax liability $518.5 $501.7
The Internal Revenue Service has examined and closed
consolidated Federal income tax returns of SCANA Corporation
through 1989, and has examined and proposed adjustments to
SCANA's Federal returns for 1990 through 1995. The Company does
not anticipate that any adjustments which might result from these
examinations will have a significant impact on the results of
operations, cash flows or financial position of the Company.
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the
Company's financial instruments at December 31, 1997 and 1996 are
as follows:
1997 1996
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Millions of Dollars)
Assets:
Cash and temporary cash
investments $ 6.0 $ 6.0 $ 5.4 $ 5.4
Investments 5.3 5.3 0.6 0.6
Liabilities:
Short-term borrowings 13.3 13.3 90.0 90.0
Long-term debt 1,309.5 1,384.7 1,319.5 1,352.9
Preferred stock (subject
to purchase or sinking funds) 12.5 11.3 45.4 44.3
53
The information presented herein is based on pertinent
information available to the Company as of December 31, 1997 and
1996. Although the Company is not aware of any factors that
would significantly affect the estimated fair value amounts, such
financial instruments have not been comprehensively revalued
since December 31, 1997, and the current estimated fair value may
differ significantly from the estimated fair value at that date.
The following methods and assumptions were used to estimate
the fair value of the above classes of financial instruments:
Cash and temporary cash investments, including commercial
paper, repurchase agreements, treasury bills and notes, are
valued at their carrying amount.
Fair values of investments and long-term debt are based on
quoted market prices of the instruments or similar instruments,
or for those instruments for which there are no quoted market
prices available, fair values are based on net present value
calculations. Investments which are not considered to be
financial instruments have been excluded from the carrying amount
and estimated fair value. Settlement of long term debt may not
be possible or may not be a prudent management decision.
Short-term borrowings are valued at their carrying amount.
The fair value of preferred stock (subject to purchase or
sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in
an actual sale or settlement have not been taken into
consideration.
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its
committed lines of credit. Commercial paper borrowings are for
270 days or less. Details of lines of credit (including
uncommitted lines of credit) and short-term borrowings, excluding
amounts classified as long-term (Notes 3 and 4), at December 31,
1997 and 1996 and for the years then ended are as follows:
1997 1996
(Millions of dollars)
Authorized lines of credit at year-end $315 $145.0
Unused lines of credit at year-end $315 $145.0
Short-term borrowings outstanding at
year-end:
Commercial paper $13.3 $ 90.0
Weighted average interest rate 5.90% 5.53%
54
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
SCANA and Westvaco Corporation have formed a limited
liability company, Cogen South LLC, to build and operate a $170
million cogeneration facility at Westvaco's Kraft Division Paper
Mill in North Charleston, South Carolina. SCANA and Westvaco
each own a 50% interest in LLC. The facility will provide
industrial process steam for the Westvaco paper mill and shaft
horsepower to enable the Company to generate up to 99 megawatts
of electricity. In addition to the cogeneration LLC, Westvaco
has entered into a 20-year contract with the Company for all its
electricity requirements at the North Charleston mill at the
Company's standard industrial rate. Construction of the plant
began in September 1996 and it is expected to be operational in
the fall of 1998.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with
public liability for a nuclear incident, currently establishes
the liability limit for third-party claims associated with any
nuclear incident at $8.9 billion. Each reactor licensee is
currently liable for up to $79.3 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 Summer Station,
would be approximately $52.9 million per incident, but not more
than $6.7 million per year.
The Company currently maintains policies (for itself and on
behalf of the PSA) 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 facilities covered under
the NEIL program. Based on the current annual premium, this
retroactive premium would not exceed $5.1 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and
expenses arising from a nuclear incident at Summer Station exceed
the policy limits of insurance, or to the extent such insurance
becomes unavailable in the future, and to the extent that the
Company's rates would not recover the cost of any purchased
replacement power, the Company will retain the risk of loss as a
self-insurer. The Company has no reason to anticipate a serious
nuclear incident at Summer Station. If such an incident were to
occur, it could have a material adverse impact on the Company's
results of operations, cash flows and financial position.
C. Environmental
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 before cleanup is initiated. The PRPs have
agreed with the EPA to participate in an
55
innovative approach to site investigation and cleanup called
"Superfund Accelerated Cleanup Model," allowing the pre-cleanup
site investigation process to be compressed significantly. The
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 conditionally approved a Remedial Investigation
Report in March 1997. Although the Company is continuing to
investigate cost-effective clean-up methodologies, further work
is pending EPA approval of the final draft of the Remedial
Investigation Report. See Note 1L.
In October 1996 the City of Charleston and the Company
settled all environmental claims the City may have had against
the Company involving the Calhoun Park area for a payment of $26
million over four years (1996 through 1999) by the Company to the
City. The Company is recovering the amount of the settlement,
which does not encompass site assessment and cleanup costs,
through rates in the same manner as other amounts accrued for
site assessments and cleanup as discussed above. See Note 1L.
As part of the environmental settlement, the Company has agreed
to construct an 1,100 space parking garage on the Calhoun Park
site and to transfer the facility to the City in exchange for a
20-year municipal bond backed by revenues from the parking garage
and a mortgage on the parking garage. Construction is expected
to begin in 1998. The total amount of the bond is not to exceed
$16.9 million, the maximum expected project cost.
The Company owns three other decommissioned manufactured gas
plant sites which contain residues of by-product chemicals. The
Company is investigating the sites to monitor the nature and
extent of the residual contamination.
D. Franchise Agreements
See Note 3 for a discussion of an electric franchise
agreement between the Company and the City of Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation
incidental to its business operations which management
anticipates will be resolved without material loss to the
Company. No estimate of the range of loss from these matters can
currently be determined.
56
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1997, 1996 and 1995 and
for the years then ended is as follows:
1997
Electric Gas Transit Total
(Millions of Dollars)
Operating revenues $1,103 $234 $ 1 $1,338
Operating expenses,
excluding depreciation
and amortization 710 201 5 916
Depreciation and
amortization 129 11 - 140
Total operating expenses 839 212 5 1,056
Operating income (loss) $ 264 $ 22 $(4) 282
Add - Other income, net 9
Less - Interest charges, net 95
Less - Preferred Dividend Requirements,
including the Company -
Obligated Mandatorily
Redeemable Preferred
Securities 10
Net income $ 186
Capital expenditures:
Identifiable $218 $ 15 $ - $ 233
Utilized for overall Company operations 32
Total $ 265
Identifiable assets at
December 31, 1997:
Utility plant, net $2,951 $221 $ 2 $3,174
Inventories 69 2 - 71
Total $3,020 $223 $ - 3,245
Other assets 809
Total assets $4,054
57
1996
Electric Gas Transit Total
(Millions of Dollars)
Operating revenues $1,107 $ 235 $ 3 $1,345
Operating expenses,
excluding depreciation
and amortization 711 204 9 924
Depreciation and
amortization 123 12 - 135
Total operating expenses 834 216 9 1,059
Operating income (loss) $ 273 $ 19 $(6) 286
Add - Other income, net 4
Less - Interest charges, net 9
Less - Preferred stock dividends 6
Net income $ 185
Capital expenditures:
Identifiable $ 197 $ 19 $ - $ 216
Utilized for overall Company operations 24
Total 240
Identifiable assets at
December 31, 1996:
Utility plant, net $2,870 $ 217 $ 2 $3,089
Inventories 76 2 - 78
Total $2,946 $ 219 $ 2 3,167
Other assets 792
Total assets $3,959
1995
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $1,006 $ 201 $ 4 $1,211
Operating expenses,
excluding depreciation
and amortization 657 170 10 837
Depreciation and
amortization 104 13 1 118
Total operating expenses 761 183 11 955
Operating income (loss) $ 245 $ 18 $(7) 256
Add - Other income, net 9
Less - Interest charges, net 96
Less - Preferred stock dividends 6
Net income $ 163
Capital expenditures:
Identifiable $ 245 $ 20 $ - $ 265
Utilized for overall Company operations 28
Total $ 293
Identifiable assets at
December 31, 1995:
Utility plant, net $2,851 $ 210 $ 2 $3,063
Inventories 77 2 - 79
Total $2,928 $ 212 $ 2 3,142
Other assets 661
Total assets $3,803
58
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1997
(Millions of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $337 $289 $377 $335 $1,338
Operating income 74 52 93 63 282
Net Income 50 30 73 42 195
1996
(Millions of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $354 $311 $365 $315 $1,345
Operating income 79 59 90 57 285
Net Income 56 35 66 33 190
59
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
The directors listed below were elected April 24, 1997 to hold
office until the next annual meeting of the Company's stockholders on
April 23, 1998.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 54 For more than five years, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).
For more than five years, Chairman and Chief
Executive Officer of Amick Processing,
Inc. and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia,
SC.
James A. Bennett 37 Since December 1994, Senior Vice President
(1997) and Director of Community Banking of First
Citizens Bank, Columbia, SC.
From March 1991 to December 1994,
President of Victory Savings Bank,
Columbia, SC.
Director, SCANA Corporation
William B. Bookhart, Jr. 56 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 68 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC;
Member, Advisory Board of Liberty Mutual
Insurance Group.
Hugh M. Chapman 65 Since June 30, 1997, retired from
(1988) NationsBank South, Atlanta, GA
(a division of NationsBank Corporation,
bank holding company).
For more than five years prior to June
30, 1997 Chairman of NationsBank South,
Atlanta, GA
Director, SCANA Corporation, Columbia, SC;
West Point-Stevens.
60
Name and Year First
Became Director Age Principal Occupation; Directorships
Elaine T. Freeman 62 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg,
SC.
Director, National Bank of South Carolina,
Columbia, SC; SCANA Corporation,
Columbia, SC.
Lawrence M. Gressette, Jr. 66 Since February 28, 1997, Chairman Emeritus
(1987) of SCANA Corporation.
For more than five years prior to
February 28, 1997, Chairman of the
Board and Chief Executive Officer
of SCANA Corporation and Chairman
of the Board and Chief Executive
Officer of all SCANA subsidiaries,
including the Company.
For more than five years prior to
December 13, 1995, President of
SCANA Corporation.
Director, Wachovia Corporation, Winston-
Salem, NC; Powertel, Inc., West Point, GA;
SCANA Corporation, Columbia, SC.
W. Hayne Hipp 58 For more than five years, President and
(1983) Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance
and broadcasting holding company).
Director, The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC; SCANA Corporation,
Columbia, SC.
F. Creighton McMaster 68 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor
of petroleum products).
Director, First Union South Carolina,
Greenville, SC; SCANA Corporation,
Columbia, SC.
Lynne M. Miller 46 For more than five years, President of
(1997) Environmental Strategies Corporation,
Reston, VA (environmental consulting
and engineering firm).
Director, SCANA Corporation, Columbia, SC.
John B. Rhodes 67 For more than five years, Chairman and
(1967) Chief Executive Officer, Rhodes Oil
Company, Inc., Walterboro, SC
(distributor of petroleum products).
Director, SCANA Corporation, Columbia, SC.
61
Name and Year First
Became Director Age Principal Occupation; Directorships
Maceo K. Sloan 48 For more than five years, Chairman,
(1997) President and CEO of Sloan Financial
Group, Inc. and Chairman, President
and CEO of NCM Capital
Management Group, Inc.
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 51 Since March 1, 1997, Chairman and Chief
(1991) Executive Officer of SCANA Corporation.
From August 21, 1996 to March 1, 1997, Chief
Operating Officer of SCANA Corporation.
Since December 13, 1995, President of SCANA
Corporation.
From May 1, 1994 to December 13, 1995,
Executive Vice President of SCANA
Corporation.
Since August 25, 1993, Assistant Secretary
of SCANA Corporation and all of its
subsidiaries, including the Company.
From August 28, 1991 to February 20, 1996,
Chief Financial Officer of the Company.
For more than five years prior to May 1,
1994, Senior Vice President of SCANA
Corporation.
For more than five years prior to February
20, 1996, Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC;
Powertel, Inc., West Point, GA,
ITC^DeltaCom Board Member, West Point, GA.
and Wachovia Bank, N. A., Columbia, S. C.
62
EXECUTIVE OFFICERS OF THE COMPANY
The Company's officers are elected at the annual organizational meeting of the
Board of Directors and hold office until the next such organizational meeting,
unless the Board of Directors shall otherwise determine, or unless a resignation is
submitted.
Positions Held During
Name Age Past Five Years Dates
W.B. Timmerman 51 Chairman of the Board and
Chief Executive Officer 1997-present
Chief Operating Officer
of SCANA 1996-1997
President of SCANA 1995-present
President of SCANA
Communications, Inc.,
an affiliate 1996-1997
Executive Vice President, 1994-1995
SCANA
Assistant Secretary 1993-1996
Chief Financial Officer, *-1996
SCANA
Controller, SCANA *-1996
Senior Vice President, *-1994
SCANA
J. L. Skolds 47 SCANA Executive -
Electric Group 1997-present
President and Chief
Operating Officer 1996-present
Senior Vice President -
Generation 1994-1996
Vice President - Nuclear
Operations *-1994
G.J. Bullwinkel, Jr. 49 President of SCANA
Communications, Inc. 1997-present
Senior Vice President-
Retail Electric 1995-present
Senior Vice President-
Fossil & Hydro Production *-1994
W.A. Darby 52 Senior Vice President -
Gas, SCANA Gas Group 1996-present
Vice President-Gas Operations *-1996
President and Treasurer of
ServiceCare 1996-present
General Manager of ServiceCare,
Inc., an affiliate 1994-1996
K. B. Marsh 42 Vice President - Finance,
Chief Financial Officer
and Controller - SCANA 1996-present
Vice President - Finance,
Treasurer and Secretary,
SCANA *-1996
Vice President 1996-present
*Indicates position held at least since March 1, 1993
63
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of the Company's common stock is held by its parent, SCANA
Corporation. The required forms indicate that no equity securities of
the Company are owned by its directors and executive officers. Based
solely on a review of the copies of such forms and amendments
furnished to the Company and written representations from the
executive officers and directors, the Company believes that during
1997 all Section 16(a) filing requirements applicable to its executive
officers, directors and greater than 10% beneficial owners were
complied with.
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to
compensation paid or accrued during the years 1997, 1996 and 1995 to
the Chief Executive Officer of the Company, to each of the other four
most highly compensated executive officers of the Company during 1997,
who were serving as executive officers of the Company at the end of
1997 and to L. M. Gressette, Jr., the Company's former Chief Executive
Officer, who retired in February 1997.
SUMMARY COMPENSATION TABLE
Name and Principal Year Annual Compensation Long-Term
Position Compensation
(1) (2) (3) (4)
Salary Bonus Other Payouts
($) ($) Annual LTIP (5)
Compensation Payouts All Other
($) ($) Compensation
($)
W. B. Timmerman
Chairman, President 1997 400,634 318,815 12,220 88,338 24,038
and Chief Executive 1996 335,266 196,832 6,399 109,819 20,116
Officer and Director 1995 254,214 101,588 987 150,353 15,127
- - SCANA Corporation
J. L. Skolds
SCANA Executive - 1997 277,132 161,677 5,777 70,283 16,628
Electric Group, 1996 215,708 114,099 2,453 55,513 12,943
President and Chief 1995 176,156 74,151 54 76,128 10,569
Operating Officer -
South Carolina Electric
and Gas Company
G. J. Bullwinkel 1997 219,273 92,796 7,776 70,283 13,156
Senior Vice President 1996 205,980 90,370 3,710 66,374 12,359
- - Retail Electric 1995 189,097 70,904 487 90,402 11,346
K. B. Marsh 1997 199,845 104,276 2,947 44,491 11,991
Vice President, Chief 1996 166,616 75,667 1,189 46,462 9,997
Financial Officer and 1995 133,768 63,757 51,390 8,026
Controller - SCANA Corp.
W. A. Darby 1997 169,606 73,800 7,025 44,491 10,176
Senior Vice President, 1996 157,659 54,090 3,566 46,462 9,460
Gas Operations and 1995 147,729 44,195 16 63,757 8,864
President of ServiceCare
L. M. Gressette, Jr. 1997 132,584 79,704 167,003 399,950
Chairman Emeritus and 1996 483,952 274,320 5,998 285,408 29,037
Chairman of the Executive 1995 449,246 197,500 65,779 390,156 26,955
Committee - SCANA Corp.
- -----------------
(1) Reflects actual salary paid in 1997 from SCANA and its subsidiaries.
(2) Payments under the Performance Incentive Plan described hereafter.
(3) For 1997, other annual compensation consists of life insurance premiums on policies
owned by named executive officers and payments to cover taxes on benefits of $9,521
and $2,699 for Mr. Timmerman; $4,694 and $1,083 for Mr. Skolds; $7,151 and $625 for
Mr. Bullwinkel; $2,683 and $264 for Mr. Marsh; and $6,886 and $139 for Mr. Darby.
(4) Payments under the Performance Share Plan described hereafter.
(5) All other compensation for all named executive officers except Mr. Gressette, consists
solely of SCANA contributions to defined contribution plans based on the funding
formula applicable to all Company employees. For Mr. Gressette, all other compensation
for 1997 consists of payments under SCANA and its subsidiaries' retirement plans of
$378,681 and Company contributions to defined contribution plans of $21,269.
64
The following table shows the target awards made in 1997, for potential payment in
2000, under the Performance Share Plan for officers of SCANA and its subsidiaries', and
estimated future payouts under that plan at threshold, target and maximum levels for the
named executive officers named in the Summary Compensation Table on the preceding page.
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1997 TO BE PAID IN 2000
Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation
Name Rights (#) or Payout
Threshold Target Maximum
($ or #) ($ or #) ($ or #)
W. B. Timmerman 11,030 1997-1999 4,412 11,030 16,545
J. L. Skolds 5,560 1997-1999 2,224 5,560 8,340
G. J. Bullwinkel 3,010 1997-1999 1,204 3,010 4,515
K. B. Marsh 3,010 1997-1999 1,204 3,010 4,515
W. A. Darby 2,040 1997-1999 820 2,040 3,060
L. M. Gressette, Jr. 282 1997-1999 112 282 423
Payouts will occur when SCANA's Total Shareholder Return
("TSR") is in the top two-thirds of a peer group of utilities,
and will vary based on SCANA's ranking against the peer group.
Executives earn threshold payouts at the 33rd percentile of
three-year performance. Target payouts will be made at the 50th
percentile of three-year performance. Maximum payouts will be
made when the TSR is at or above the 75th percentile of the peer
group. Payments will be made on a sliding scale for performance
between threshold and target and target and maximum. No payouts
will be earned if performance is at less than the 33rd
percentile. Awards are denominated in shares of SCANA Common
Stock and may be paid in either stock or cash or a combination of
both.
DEFINED BENEFIT PLANS
In addition to the qualified Retirement Plan for all
employees, SCANA has Supplemental Executive Retirement Plans
("SERPs") for certain eligible employees, including officers of
its subsidiaries. A SERP is an unfunded plan which provides for
benefit payments in addition to those payable under a qualified
retirement plan. It maintains uniform application of the
Retirement Plan benefit formula and would provide, among other
benefits, payment of Retirement Plan formula pension benefits, if
any, which exceed those payable under the Internal Revenue Code
("IRC") maximum benefit limitations.
65
The following table illustrates the estimated maximum annual
benefits payable upon retirement at normal retirement date under
the Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$150,000 $ 41,965 $ 55,953 $ 69,942 $ 83,930 $ 86,668
200,000 56,965 75,953 94,942 113,930 117,918
250,000 71,965 95,953 119,942 143,930 149,168
300,000 86,965 115,953 144,942 173,930 180,418
350,000 101,965 135,953 169,942 203,930 211,668
400,000 116,965 155,953 194,942 233,930 242,918
450,000 131,965 175,953 219,942 263,930 274,168
500,000 146,965 195,953 244,942 293,930 305,418
550,000 161,965 215,953 269,942 323,930 336,668
600,000 176,965 235,953 294,942 353,930 367,918
650,000 191,965 255,953 319,942 383,930 399,168
700,000 206,965 275,953 344,942 413,930 430,418
750,000 221,965 295,953 369,942 443,930 461,668
800,000 236,965 315,953 394,942 473,930 492,918
For all the executive officers named in the Summary
Compensation Table for 1997, the compensation shown in the column
labeled "Salary" of the Summary Compensation Table is covered by
the Retirement Plan and/or a SERP. As of December 31, 1997,
Messrs. Timmerman, Skolds, Bullwinkel, Marsh and Darby had credited
service under the Retirement Plan (or its equivalent under the
SERP) of 19, 11, 26, 13 and 29 years, respectively. Mr. Gressette
currently is receiving a monthly benefit of $28,380 under the
Retirement Plan and a SERP. Benefits are computed based on a
straight-life annuity with an unreduced 60% surviving spouse
benefit. The amounts in this table assume continuation of the
primary Social Security benefits in effect at January 1, 1998, and
are not subject to any deduction for Social Security or other
offset amounts.
The Company also has a Key Employee Retention Plan (the "Key
Employee Retention Plan") covering officers and certain other
executive employees that provides supplemental retirement and/or
death benefits for participants. Under the plan, each participant
may elect to receive either (i) a monthly retirement benefit for
180 months upon retirement at or after age 65, equal to 25% of the
average monthly salary of the participant over his final 36 months
of employment prior to age 65, or (ii) an optional death benefit
payable monthly to a participant's designated beneficiary for 180
months, in an amount equal to 35% of the average monthly salary of
the participant over his final 36 months of employment prior to age
65. In the event of the participant's death prior to age 65, the
Company will pay to the participant's designated beneficiary for
180 months, a monthly benefit equal to 50% of such participant's
base monthly salary in effect at death.
All of the executive officers named in the Summary Compensation
Table are participating in the plan. Mr. Gressette is receiving an
annual benefit of $113,854 under the Key Employee Retention Plan.
The estimated annual retirement benefits payable at age 65, based
on projected eligible compensation (assuming increases of 4% per
year) to the other persons named in the Summary Compensation Table
are as follows: Mr. Timmerman-$170,199; Mr. Skolds-$135,858; Mr.
Bullwinkel-$96,589 ; Mr. Marsh-$119,695 and Mr. Darby-$67,006.
66
TERMINATION, SEVERANCE AND CHANGE IN CONTROL ARRANGEMENTS
Since its approval by the Board on December 18, 1996, SCANA
Corporation has maintained an Executive Benefit Plan Trust (the
"Trust"). The purpose of the Trust and the related plans is to
help retain and attract quality leadership in key company positions
in the current transitional environment of the electric utility
industry. The Trust is used to receive contributions which may be
used to pay the deferred compensation benefits of certain
directors, executives and other key employees of SCANA and its
subsidiaries' in the event of a Change in Control (as defined in
the Trust). All the executive officers named in the Summary
Compensation Table participate in certain of the plans listed below
(the "Plans") which are covered by the Trust.
(1) SCANA Corporation Voluntary Deferral Plan
(2) SCANA Corporation Supplementary Voluntary Deferral Plan
(3) SCANA Corporation Key Employee Retention Plan
(4) SCANA Corporation Supplemental Executive Retirement Plan
(5) SCANA Corporation Performance Share Plan
(6) SCANA Corporation Annual Incentive Plan
(7) SCANA Corporation Key Executive Severance Benefits Plan
(8) SCANA Corporation Supplementary Key Executive Severance
Benefits Plan
The Trust and the Plans provide flexibility to the Company in
responding to a Potential Change in Control (as defined in the
Trust) depending upon whether the Change in Control would be viewed
as being "hostile" or "friendly". This flexibility includes the
ability to deposit and withdraw Company contributions up to the
point of a Change in Control, and to affect the number of plan
participants who may be eligible for benefit distributions upon, or
following, a Change in Control. The Plans listed above at items
(7) and (8) cover all the named executive officers (except Mr.
Gressette).
The Key Executive Severance Benefits Plan is operative as a
"single trigger" plan, meaning that upon the occurrence of a
"hostile" Change in Control, benefits provided under plans (1)
through (6) above would be distributed in a lump sum. Under the
terms of the Trust, in the event of a Change in Control that would
trigger operation of the Key Executive Severance Benefits Plan, Mr.
Gressette would receive immediate payout of all benefits under any
of the Plans in which he is then participating.
In contrast, the Supplementary Key Executive Severance Benefits
Plan (the "Supplementary Plan") is operative for a period of
twenty-four months following a Change in Control which prior to its
occurrence is viewed as being "friendly". In this circumstance,
the Key Executive Severance Benefits Plan is inoperative. The
Supplementary Plan is a "double trigger" plan that would pay
benefits in lieu of those otherwise provided under plans (1)
through (6) in either of two circumstances: (a) the participant's
involuntary termination of employment without "Just Cause", or (b)
the participant's voluntary termination of employment for "Good
Reason" (as these terms are defined in the Supplementary Plan).
Benefit distributions relative to a Change in Control, as to
which either the Key Executive Severance Benefits Plan or the
Supplementary Plan is operative, will be grossed up to include
estimated federal, state and local income taxes and any applicable
excise taxes owed by Plan participants on those benefits, and paid
in a lump sum. The benefit distributions would also be calculated
so as to include, in addition to other benefits:
67
(a) Three times the sum of: (1) the officer's annual base
salary in effect as of the Change in Control and (2) the larger of
(i) the officer's full targeted annual incentive opportunity in
effect as of the Change in Control under the Annual Incentive Plan,
or (ii) the officer's average of actual annual incentive bonuses
received during the prior three years under the Annual Incentive
Plan; and
(b) an amount equal to the projected cost for coverage for three
full years following the Change in Control as though the officer
had continued to be a Company employee with respect to medical
coverage, long-term disability coverage and either Life Plus (a
special life insurance program combining whole life and term
coverages) or group term life coverage in accordance with the
officer's actual election, in each case so as to provide
substantially the same level of coverage and benefits as the
officer enjoyed as of the date of the Change in Control.
Benefit distributions pertaining to the Voluntary Deferral Plan
would be calculated as of the date of the Change in Control
inclusive of interest provided under the plan through such date,
and benefits pertaining to the Supplementary Voluntary Deferral
Plan would be calculated to include any implied dividends accruable
under the plan through the date of the Change in Control.
Benefit distributions pertaining to the Key Employee Retention
Plan would be calculated inclusive of projected increases to each
participant's base salary using a fixed, market competitive rate as
though the participant had reached the earlier of age 65 or
completed 35 years of service.
Benefit distributions pertaining to the Supplemental Executive
Retirement Plan would be calculated as an actuarial equivalent
through the date of the Change in Control with three additional
years of compensation at the participant's rate then in effect as
though the participant had attained age 65 and completed 35 years
of benefit service as of the date of the Change in Control and
without any early retirement or other actuarial reductions, which
benefit would then be reduced by the actuarial equivalent of the
participant's qualified plan benefit amount under the Retirement
Plan.
Benefit distributions pertaining to the Performance Share Plan
would be equal to 100% of the targeted award as granted for all
performance periods which are not yet completed as of the date of
the Change in Control. Benefit distributions pertaining to the
Annual Incentive Plan would be equal to 100% of the target award.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1997, no officer, employee or former officer of SCANA
or any of its subsidiaries served as a member of the Long-Term
Compensation Committee or the Performance Committee, except Mr.
Gressette who served as an ex-officio, non-voting member of the
Performance Committee until his retirement in February 1997 and as
a member of the Long-Term Compensation Committee following his
retirement, and Mr. Timmerman who has been an ex-officio, non-
voting member of the Performance Committee since March 1, 1997.
Although Mr. Gressette and Mr. Timmerman served as members of the
Performance Committee during 1997, neither participated in any of
its decisions concerning executive officer compensation. As a
member of the Long-Term Compensation Committee following his
retirement, Mr. Gressette participated in the decisions regarding
target awards made in 1997 under the Performance Share Plan.
68
Since January 1, 1997, SCANA and its subsidiaries including
the Company have engaged in business transactions with entities
with which Mr. Amick (a member of the Performance Committee and the
Long-Term Compensation Committee), Mr. Chapman (Chairman of both
the Performance Committee and the Long-Term Compensation Committee)
and Mr. McMaster (a member of the Long-Term Compensation Committee)
are related.
Mr. Amick is the owner of Team Amick Motor Sports, a business
that owns and operates a NASCAR sanctioned racing car. This car
participates in the Busch Grand National Racing Series. SCANA has
entered into a shared sponsorship agreement with Team Amick Motor
Sports pursuant to which SCANA will receive promotional
considerations associated with NASCAR racing for an annual fee of
$500,000.
Mr. Chapman was Chairman of NationsBank South, a division of
NationsBank Corporation until his retirement on June 30, 1997.
Since January 1, 1997, SCANA has engaged in various transactions in
which affiliates of NationsBank Corporation acted as lender or
provider of lines of credit or credit support to SCANA and its
subsidiaries. The amount paid during 1997, by SCANA and its
subsidiaries to NationsBank Corporation affiliates on account of
such transactions was $361,870. In addition, during 1997, a
NationsBank Corporation affiliate and a SCANA subsidiary have
engaged in options and futures transactions and forward contracts
relating to forecasted natural gas production. The amount paid
during 1997, by a SCANA subsidiary to NationsBank Corporation
affiliates on account of such transactions was $7,602,582. It is
anticipated that similar transactions will continue in the future.
Mr. McMaster is the President and Manager of Winnsboro
Petroleum Company. Purchases from Winnsboro Petroleum Company
totaling $61,819 for petroleum products were made during 1997, by
the Company and its subsidiaries. It is anticipated that similar
transactions will continue.
Compensation of Directors
Fees. During 1997, directors who were not employees of the
Company were paid $17,600 annually for services rendered as
directors of SCANA and its subsidiaries, including the Company,
$1,800 for each Board meeting attended and $850 for attendance at a
committee meeting which is not held on the same day as a regular
meeting of the Board. The fee for attendance at a telephone
conference meeting is $200. The fee for attendance at a conference
is $850. In addition, directors are paid, as part of their
compensation, travel, lodging and incidental expenses related to
attendance at meetings and conferences. The Board of Directors
approved a plan effective January 1, 1997, whereby non-employee
directors receive on a quarterly basis, 41% of their retainer in
shares of SCANA common stock. The purpose of the plan is to
promote the achievement of long-term objectives of SCANA by linking
the personal interests of the non-employee directors to those of
SCANA's shareholders by paying a portion of director compensation
in stock. The Company believes this linkage will further promote
the achievement of its long-term objectives.
Directors who are employees of SCANA or its subsidiaries
receive no compensation for serving as directors or attending
meetings.
In addition to regular director fees which he began to receive
following his retirement, Mr. Gressette, as a Company retiree,
received the retirement benefits described in the Summary
Compensation Table on page 64.
69
Deferral Plan. SCANA has a plan (the "Voluntary Deferral
Plan") pursuant to which directors may defer all or a portion of
their fees paid to them in cash for services rendered and meeting
attendance. Interest is earned on the deferred amounts at a rate
set by the Management Development and Corporate Committee (the
Performance Committee). Since January 1, 1997, the rate has been
set at the announced prime rate of Wachovia Bank, N. A. Mr.
Cassels and Mr. Rhodes were the only directors participating in the
plan during 1997. Mr. Cassels became a participant in January
1994, and Mr. Rhodes in July 1987. Interest credited to their
deferral accounts during 1997, was $8,609 and $27,228,
respectively.
Endowment Plan. Upon election to a second term, each director
becomes eligible to participate in the Directors' Endowment Plan,
which provides for the Company to make a tax deductible, charitable
contribution totaling $500,000 to institutions of higher education
designated by the SCANA director. A portion is contributed upon
retirement of the director and the remainder upon the director's
death. The plan is funded in part through insurance on the lives
of the directors. Designated in-state institutions of higher
education must be approved by the Chief Executive Officer. Any
out-of-state designation must be approved by the Performance
Committee. The designated institutions are reviewed on an annual
basis by the Chief Executive Officer to assure compliance with the
intent of the program. The plan is intended to reinforce the
commitment to quality higher education and is intended to enhance
the ability to attract and retain qualified board members.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The table set forth below indicates the shares of SCANA's
common stock beneficially owned as of March 10, 1998 by each
director, each of the persons named in the Summary Compensation
Table on page 64 (the "Named Executive Officer"), the directors and
current executive officers of the Company as a group.
SECURITY OWNERSHIP OF MANAGEMENT
Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature
Owner of Ownership 1 Owner of Ownership 1
B. L. Amick 3,355 W. Hayne Hipp 3,145
J. A. Bennett 669 K. M. Marsh 9,760
W. B. Bookhart, Jr. 17,973 F. C. McMaster 5,975
G. J. Bullwinkel 20,167 L. M. Miller 1,281
W. T. Cassels, Jr. 2,355 J. B. Rhodes 9,052
H. M. Chapman 6,345 J. L. Skolds 9,473
W. A. Darby 23,336 M. K. Sloan 581
E. T. Freeman 4,675 W. B. Timmerman 28,567
L. M. Gressette, Jr. 59,352
All directors and executive officers as a group (17 persons) TOTAL 206,061.
TOTAL PERCENT OF CLASS 0.2%
- ----------
1 Includes shares owned by close relatives, the beneficial
ownership of which is disclaimed by the director, nominee or Named
Executive Officers, as follows:
Mr. Amick - 480; Mr. Bookhart - 5,029; Mr. Gressette -
1,060; and Mr. McMaster - 2,000; and by all directors, nominees and
current executive officers - 8,569 in total.
Includes shares purchased through December 31, 1997, but not
thereafter, by the Trustee under the Company's Stock Purchase-
Savings Plan (the Savings Plan).
The information set forth above as to the security ownership
of common stock has been furnished to the Company by such persons.
70
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related
transactions, see Item 11, "Compensation Committee Interlocks and
Insider Participation."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
Financial Statements and Schedules
See Index to Consolidated Financial Statements and
Supplementary Data on page 33.
Exhibits Filed
Exhibits required to be filed with this Annual Report on Form
10-K are listed in the Exhibit Index following the signature page.
Certain of such exhibits which have heretofore been filed with the
Securities and Exchange Commission and which are designated by
reference to their exhibit number in prior filings are hereby
incorporated herein by reference and made a part hereof.
As permitted under Item 601(b)(4)(iii), instruments defining
the rights of holders of long-term debt of less than 10 percent of
the total consolidated assets of the Company and its subsidiaries,
have been omitted and the Company agrees to furnish a copy of such
instruments to the Commission upon request.
Reports on Form 8-K
None
71
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
(REGISTRANT) SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY (SIGNATURE) s/J. L. Skolds
(NAME AND TITLE) J. L. Skolds, President and Chief
Operating Officer
DATE February 17, 1998
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
(i) Principal executive officer:
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman Chairman of the Board,
Chief Executive Officer and Director
DATE February 17, 1998
(ii) Principal financial officer:
BY (SIGNATURE) s/K. B. Marsh
(NAME AND TITLE) K. B. Marsh, Chief Financial Officer
DATE February 17, 1998
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and Controller
DATE February 17, 1998
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 17, 1998
BY (SIGNATURE) s/J. A. Bennett
(NAME AND TITLE) J. A. Bennett, Director
DATE February 17, 1998
72
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 17, 1998
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 17, 1998
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 17, 1998
BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 17, 1998
BY (SIGNATURE) s/L. M. Gressette, Jr.
(NAME AND TITLE) L. M. Gressette, Jr., Director
DATE February 17, 1998
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 17, 1998
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 17, 1998
BY (SIGNATURE) s/L. M. Miller
(NAME AND TITLE) L. M. Miller, Director
DATE February 17, 1998
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 17, 1998
BY (SIGNATURE) s/M. K. Sloan
(NAME AND TITLE) M. K. Sloan, Director
DATE February 17, 1998
73
SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially
EXHIBIT INDEX Numbered
Number Pages
2. Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession
Not Applicable
3. Articles of Incorporation and By-Laws
A. Restated Articles of Incorporation of the
Company as adopted on December 15, 1993
(Exhibit 3-A to Form 10-Q for the quarter
ended June 30, 1994, File No. 1-3375).................... #
B. Articles of Amendment, dated June 7, 1994,
filed June 9, 1994 (Exhibit 3-B to Form 10-Q
for the quarter ended June 30, 1994, File No. 1-3375).... #
C. Articles of Amendment, dated November 9, 1994
(Exhibit 3-C to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
D. Articles of Amendment, dated December 9, 1994
(Exhibit 3-D to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
E. Articles of Correction, dated January 17, 1995
(Exhibit 3-E to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
F. Articles of Amendment, dated January 13, 1995
and filed January 17, 1995 (Exhibit 3-F to
Form 10-K for the year ended December 31, 1994,
File No. 1-3375)......................................... #
G. Articles of Amendment dated March 31, 1995
(Exhibit 3-G to Form 10-Q for the quarter
ended March 31, 1995, File No. 1-3375)................... #
H. Articles of Correction - Amendment to Statement
filed March 31, 1995, dated December 13, 1995
(Exhibit 3-H to Form 10-K for the year ended
December 31. 1995, File No. 1-3375)...................... #
I. Articles of Amendment dated December 13, 1995
(Exhibit 3-I to Form 10-K for the year ended
December 31, 1995, File No. 1-3375)...................... #
J. Copy of By-Laws of the Company as revised and
amended on December 17, 1997 (Filed herewith)............ 77
K. Articles of Amendment dated February 18, 1997
(Exhibit 3-L to Registration Statement No. 333-24919).... #
L. Articles of Amendment dated February 21, 1997
(Exhibit 3-L to Form 10-Q for the quarter ended
March 31, 1997).......................................... #
M. Articles of Amendment dated April 22, 1997
(Exhibit 3-M to Form 10-Q for the quarter
ended June 30, 1997)..................................... #
4. Instruments Defining the Rights of Security
Holders, Including Indentures
A. 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 (Exhibit 2-B to
Registration No. 2-26459)................................ #
B. Fourth Supplemental Indenture dated as of April 1,
1950, to Indenture referred to in Exhibit 4A,
pursuant to which the Company assumed said
Indenture (Exhibit 2-C to Registration No. 2-26459)...... #
# Incorporated herein by reference as indicated.
74
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
4. (continued)
C. Fifth through Fifty-second Supplemental Indentures
to Indenture referred to in Exhibit 4A 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. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-Q 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 4-C to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 4-C 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
D. Indenture dated as of April 1, 1993 from South Carolina
Electric & Gas Company to NationsBank of Georgia, National
Association (Filed as Exhibit 4-F to Registration
Statement No. 33-49421)......................................... #
E. First Supplemental Indenture to Indenture referred to
in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-49421)......................... #
# Incorporated herein by reference as indicated.
75
SOUTH CAROLINA ELECTRIC & GAS COMPANY
EXHIBIT INDEX
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
F. Second Supplemental Indenture to Indenture referred to
in 4-D dated as of June 15, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-57955)......................... #
G. Trust Agreement for SCE&G Trust I (Filed herewith).............. 93
H. Certificate of Trust for SCE&G Trust I (Filed herewith)......... 96
I. Form of Junior Subordinated Indenture for SCE&G Trust I
(Filed herewith)................................................ 97
J. Form of Guarantee Agreement for SCE&G Trust I (Filed
herewith)....................................................... 177
K. Form of Amended & Restated Trust Agreement for SCE&G
Trust I (Filed herewith)........................................ 198
9. Voting Trust Agreement
Not Applicable
10. Material Contracts
A. Copy of Supplemental Executive Retirement Plan
(Exhibit 10-A to Form 10-K for the year ended
December 31, 1980)............................................ 276
11. Statement Re Computation of Per Share Earnings
Not Applicable
12. Statement re Computation of Ratios (Filed herewith)................ 295
13. Annual Report to Security Holders, Form 10-Q or
Quarterly Report to Security Holders
Not Applicable
16. Letter Re Change in Certifying Accountant
Not Applicable
18. Letter Re Change in Accounting Principles
Not Applicable
21. Subsidiaries of the Registrant
Not Applicable
22. Published Report Regarding Matters Submitted to
Vote of Security Holders
Not Applicable
23. Consents of Experts and Counsel
Consent of Deloitte & Touche LLP................................... 299
24.