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
[FEE REQUIRED]
For the fiscal year ended December 31, 19951997
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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
The Class is comprised of the following series of Cumulative
Preferred Stock, par value $50 per share or $100 per share,
having a periodic sinking fund:
9.40% Cumulative Preferred 8.72% Cumulative Preferred
Stock par value $50 per Stock par value $50
share per share
8.12% Cumulative Preferred 7.70% Cumulative Preferred
Stock par value $100 Stock par value $100
per share per shareNone
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 stockand non-voting
common equity held by nonaffiliatesnon-affiliates of the registrant. The
aggregate market value shall be computed by reference to the price
at which the stockcommon equity was sold, or the average bid and asked
prices of such stock,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 stockand non-voting common
equity held by non-
affiliatesnon-affiliates of the registrant as of February 29, 199627,
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 29, 199627, 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 .......................................... 1920
Item 3. Legal Proceedings ................................... 2122
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 2122
PART II
Item 5. Market for Registrant's Common StockEquity
and Related Security Holder Matters ................ 21Stockholder Matters..................... 22
Item 6. Selected Financial Data ............................. 2223
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ...... 2324
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk......................................... 33
Item 8. Financial Statements and Supplementary Data ......... 3033
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 5560
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 5560
Item 11. Executive Compensation .............................. 6064
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 6471
Item 13. Certain Relationships and Related Transactions ...... 6571
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 6571
SIGNATURES ........................................................ 6672
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 millionMillion 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 ownedCoal-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 3,7213,774
full-time, permanent employees as of December 31, 19951997 as compared
to 4,0093,637 full-time, permanent employees as of December 31, 1994.1996.
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 areasarea of Columbia, and Charleston, 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 20,00021,000 square miles. The total
population of the counties representing the Company's combined
service area is approximately 2.32.4 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, 1995, 19941997, 1996 and 19931995 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 regulatory protection. Future deregulationregulation.
Deregulation of electric wholesale and retail markets will createis 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 market priceprices 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. The CompanySCE&G
has undertaken a variety of initiatives, including reductions in
operation and maintenance costs, and in staffing levels. In January 1996 the PSC
approved (as discussed under "Capital Requirements and Financing
5
Program") the accelerated recovery of
the Company'sSCE&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 qualifiedeligible to apply this accounting
treatment and may be required to eliminate such regulatory assets
from its balance sheet. Such an eventAlthough 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,
19951997.
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 $116$977.1 million and $4$659.1 million, of regulatory assets and
liabilities, respectively, excluding amounts related to net
accumulated deferred income tax assets of approximately $33
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 expandscontinues its ongoing construction
program it is necessary to seek increases in rates. On July 10, 1995,As a result
the Company filed an application with the PSC for an increase in
retail electric rates.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 willwere
designed to produce additional revenues, based on a test year, of
approximately $67.5 million annually. The increase will behas 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 6.47%.87%, commenced on
January 15, 1996. The second phase will bewas implemented in January 1997 and will produce additional revenues of
approximately $8.0 million annually, or .87% more than current
rates.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 substantially all (excluding accumulated deferred
income taxes)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 future financial position and
resultselectric revenues. The FERC rejected the transfer of
operations will be affected bydepreciation reserves for rates subject to its ability to obtain
adequate and timely rate and other regulatory relief. (See
"Regulation.")jurisdiction.
During 19961998 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 77%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.
6
The Company's revised estimates of its cash requirements for
construction and nuclear fuel expenditures, which are subject to
continuing review and adjustment, for 19961998 and the four-yeartwo-year period
1997-2000 as now scheduled,1999-2000 are as follows:
Type of Facilities 1997-2000 1996
(Thousands1999-2000 1998
(Millions of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $268,987 $ 49,03693 $ 56
Transmission. . . . . . . . . . . . . . . 92,502 17,97631 16
Distribution. . . . . . . . . . . . . . . 319,092 64,227126 46
Other . . . . . . . . . . . . . . . . . . 34,152 13,83522 13
Nuclear Fuel. . . . . . . . . . . . . . . . 86,413 21,14733 23
Gas . . . . . . . . . . . . . . . . . . . . 94,147 16,91835 13
Common. . . . . . . . . . . . . . . . . . . 34,089 34,63327 29
Other . . . . . . . . . . . . . . . . . . . 1,511 553- 1
Total . . . . . . . . . . . . . . $930,893 $218,325$367 $197
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program
for the periods 1996 and 1997-2000, shown in the above table,
include costs of the projects described below.
The Company entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina.
Construction of the plant started in November 1992. Commercial
operation began in January 1996. The cost of the Cope plant,
excluding AFC, is $410.9 million. In addition, the
transmission lines for interconnection with the Company's system
cost $22.5 million. Approximately $9.8 million of the amounts
included in the above table for 1996 relate to the completion of
the Cope plant.
During 19951997 the Company expended approximately $15.9$23.1 million
as part of a program to extend the operating lives of certain non-nuclearnon-
nuclear generating facilities. Additional improvements to be made
under the program to be made during 19961998, included in the table above, are
estimated to cost approximately $19.9$57.4 million.
Additional Capital Requirements7
In addition to the Company's capital requirements for 19961998
described in "Capital Requirements" above, approximately $21.2$47.7 million will be required for
refunding and retiring outstanding securities and obligations. For
the years 1997-2000,1999-2002, the Company has an aggregate of $292.8$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 $9.8$2.2
million of purchase or sinking fund requirements for preferred
stock.
ActualSCANA 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 expenditures may varyand 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 estimates set
forth above duesale were used to factors such as inflation, economic
conditions, regulation, legislation, ratesreduce 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 load growth,
environmental protection standards and the cost and availabilityCompany, issued
$50 million of capital.
7
Financing Program7.55% 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, 19951997 the
Bond Ratio was 3.97.4.32. 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 $162.3$579 million at December 31, 1995)1997),
(ii) retirements of Class A Bonds (which retirement credits totaled
$64.8$67.5 million at December 31, 1995)1997), and (iii) and cash on deposit with
the Trustee.
The Company has placed a new bond indenture (New Mortgage) 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, 1995)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, 19951997
the New Bond Ratio was 5.31.
The following additional financing transaction has occurred
since December 31, 1994:
On April 12, 1995 the Company issued $100 million of First
Mortgage Bonds, 7 5/8% series due April 1, 2025 to repay
short-term borrowings.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;
provided, however, that 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 $200$250 million of unsecured
promissory notes or commercial paper with maturity dates of twelve
months or less, but not later than December 31, 1997.1999. Commercial
paper outstanding at December 31, 1997 was $13.3 million.
The Company had $165$315 million authorized and unused lines of
credit at December 31, 1995. In addition, Fuel Company has1997 including a credit agreement for a
maximum of $125$250 million with the full
amount available at December 31, 1995. The credit agreement
supportsto support the issuance of short-term commercial
paper for the
financing of nuclear and fossil fuels and sulfur dioxide emission
allowances. Fuel Company commercialpaper. Commercial paper outstanding at December 31, 19951997 and
December 31, 1996 was $76.8 million.$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, 19951997 the
Preferred Stock Ratio was 2.58.
8
2.69.
The ratios of earnings to fixed charges (SEC Method) were
3.85, 3.80, 3.41, 3.46 3.57, 2.73 and 3.323.57 for the years ended December 31,
1997, 1996, 1995, 1994 and 1993, 1992respectively.
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 1991, respectively.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 July 31, 1998.December 19, 2000. Accordingly, the amounts outstanding
have been included in long-
termlong-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, 19951997 commercial paper outstanding was
approximately $76.8$80.3 million at a weighted average interest rate
of 5.76%5.87%. (See Notes 1N1M and 4 of Notes to Consolidated Financial
Statements.)
9
ELECTRIC OPERATIONS
Electric Sales
In 19951997 residential sales of electricity accounted for 43%41% of
electric sales revenues; commercial sales 30%31%; industrial sales
20%; sales for resale 4%2%; and all other 3%6%. KWH sales by
classification for the years ended December 31, 19951997 and 19941996 are
presented below:
Sales
KWH %
Classification 1995 19941997 1996 Change
(thousands)
Residential 5,726,815 5,311,139 7.835,647,185 5,939,703 (4.92)
Commercial 5,078,185 4,848,620 4.735,321,738 5,222,517 1.90
Industrial 5,210,368 5,161,717 0.945,434,231 5,320,515 2.14
Sale for resale 1,063,064 1,024,376 3.78485,206 1,023,211 (52.58)
Other 506,806 494,030 2.59505,808 505,793 -
Total Territorial 17,585,238 16,839,882 4.43
Interchange 195,591 171,046 14.3517,394,168 18,011,739 (3.43)
Negotiated Market Share Tariff 1,459,097 895,016 63.02
Total 17,780,829 17,010,928 4.53
The Company furnishes18,853,265 18,906,755 (0.28)
Sales for resale includes electricity furnished for resale to
three municipalities fourand 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, twothree 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 public power authority. Suchelectric 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 accounted for 4%and the increase of total electric sales revenues in 1995.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
19951997 the Company recorded a net increase of 7,94310,583 electric
customers, increasing its total customers to 484,381.
9
The electric sales volume increased for the year ended
December 31, 1995 compared to the prior year as a result of
increased residential and commercial sales due to favorable
weather and customer growth.503,929. The all-time
peak demand of 3,6833,734 MW was set on August 14, 1995.
On August 8, 1995 the Company signed an agreement with the
DOE to lease the Savannah River Site's (SRS) power and steam
generation and transmission facilities. The agreement calls for
SRS to purchase all its electrical and a majority of its steam
requirements from the Company. The Company will lease (with an
option to renew) the power plant for ten years and the electrical
transmission lines for 40 years, with an option to refurbish the
facilities or build a new system.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-
CarolinasVirginia-Carolinas
Reliability Group, one of the several geographic divisions within
the Southeastern Electric Reliability Council. This councilCouncil
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
1993-1995.1995-1997.
1997 1996 1995 1994 1993
Nuclear:
Per million BTU $ .48.47 $ .51.47 $ .47.48
Coal:
Company:
Per ton $38.22 $39.27 $40.01 $39.92 $39.95
Per million BTU 1.54 1.55 1.57 1.57 1.55
GENCO:
Per ton $44.49 $41.66 $42.21 $41.85 $41.64
Per million BTU 1.61 1.62 1.63 1.63 1.62
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.261.52 $ 1.391.52 $ 1.311.26
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.
10
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 1993-19951995-1997
and the estimates for 19961998 and 1997.1999.
Percent of Total KWH Generated
Estimated Actual
1999 1998 1997 1996 1995
1994 1993
Coal 73% 69% 63% 71% 65%
76% 72%
Nuclear 2422 26 31 24 27
17 23
Hydro 3 35 5 6 5 5
Natural Gas & Oil - 2- - - 3 1 -
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, 19951997 the Company had
approximately a 73-day41-day supply of coal in inventory and GENCO had
approximately a 49-day30-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
91.5%96.1% of estimated requirements for 19961998 (approximately 5.35.8
million tons, including requirements of Williams Station).
The supply of contract coal is purchased from sevennine suppliers
located in eastern Kentucky, Tennessee and southwest Virginia.
Contract commitments, which expire at various times from 1997-
2003,1998-2006,
approximate 4.855.5 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 has not been advised by
officials of DHECis unaware that any more stringent
sulfur content requirements for existing plants are contemplated at
the State level.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) Term
Uranium Energy Resources
of Australia 9-13 1990-1997
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995Date
Enrichment USEC 12-18 1995-2005(2) 13-18 2005
Fabrication Westinghouse 1-21 1982-2009
Reprocessing None13-21 2009
(1) A region represents approximately one-third to one-half of the
nuclear core in the reactor at any one time. Region no. 1113 was
loaded in 19941997 and Region no. 1214 will be loaded in 1996.
11
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 projectedscheduled to
commence in the year 2022 when the operating license expires.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 each of
19951997 and 1994)1996)
are used to purchasepay premiums on insurance policies on the lives of
certain Company personnel. The Company is the beneficiary of
these policies. Through the purchase ofthese insurance contracts, the
12
Company is able to take advantage of income tax benefits and accrue
earnings on the fund on a tax-
deferredtax-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 19951997 residential sales accounted for 47%43% of gas sales
revenues; commercial sales 32%31%; industrial sales 21%26%. Dekatherm
sales by classification for the years ended December 31, 19951997 and
19941996 are presented below:
Sales
Dekatherms %
Classification 1995 19941997 1996 Change
Residential 12,333,769 11,531,558 7.011,919,843 14,108,058 (15.5)
Commercial 10,436,987 9,813,454 6.410,904,445 11,027,830 (1.1)
Industrial 13,467,687 10,938,713 23.115,729,424 13,909,258 13.1
Transportation gas 3,603,314 5,469,728 (34.1)2,677,448 3,108,058 (13.9)
Total 39,841,757 37,753,453 5.541,231,160 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 19951997 the Company recorded a net increase of 4,9094,139 gas
customers, increasing its total customers to 243,342.252,635.
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.
12
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.
On November 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which deregulated the markets for interstate sales of
natural gas by requiring that pipelines provide transportation
services that are equal in quality for all gas supplies whether
the customer purchases gas from the pipeline or another supplier.
The impact of this order on the Company will be primarily through
changes affecting its supplier, Pipeline Corporation.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for the purchase of alternate fuel vehicles on
Federal, state, municipal and private fleets. The Company
expects these requirements to develop business opportunities for
the sale of compressed natural gas as fuel for vehicles, but it
cannot predict the magnitude of this new market.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 19961998 to
2003.2017. 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 184,974188,000
Transco Firm Transportation 29,300105,000
Total 214,274293,000
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 $3.77$3.96 in 19951997 compared to
$4.29$4.30 in 1994.1996.
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 1,695,4891,286,570 MCF were in storage at December 31, 1995.1997.
On peak days the LNG plants can regasify up to 150,000 MCF per
day. Additionally, Pipeline Corporation had contracted for
6,450,7276,447,214 MCF of natural gas storage space of which 4,307,7964,197,154 MCF
were in storage on December 31, 1995.1997.
The Company believes that supplies under contract and
available for spot market purchase are adequate to meet existing
customer demands and to accommodate growth.
13
Curtailment Plans
The FERC has established allocation priorities applicable to
firm and interruptible capacities on interstate pipeline companies to their customers
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. In the opinion of the Company, it will be able to meet
successfully the challenges of the NEPA without any material
adverse impact on its results of operations, financial position
or business prospects.
Federal Energy Regulatory Commission
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."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 19932036
Stevens Creek 9,000 2025
Columbia 10,000 2000
Saluda 206,000 2007
Parr Shoals 14,000 2020
Fairfield Pumped Storage 512,000 2020
PursuantThe Company filed a notice of intent to the provisions of the Federal Power Act, as
amended, applications for new licenses for Neal Shoals and
Stevens Creek were filed with the FERC on December 30, 1991. No
competing applications were filed. The FERC issued a new 30-year
license for the Stevens Creek project on November 22, 1995. The
Neal Shoals license application is in the final stage of review.
The FERC has issued a Notice of Authorization for Continued
Project Operation for Neal Shoals until the FERC acts on the
Company'sfile an application
for a new license.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 United StatesFederal 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.
14
The Company has filed anIn May 1996 the FERC approved the Company's application
with the FERCestablishing open access transmission tariffs and requesting
authorization to sell bulk power to wholesale customers at marketmarket-
based rates. The application also included proposed open access
transmission tariffs. (See "National Energy Policy Act of 1992
and FERC Order 636.")
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.
For the fourth time in the last five evaluations, 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 OrderOrders 636 and 888
The Company's regulated business operations are likely to bewere impacted by
the NEPA and FERC OrderOrders No. 636.636 and 888. NEPA iswas 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 iswas 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 willcontinues
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 its operations, itscash flows, financial
position or its business prospects.
RATE MATTERS
The following table presents a summary of significant rate
activity for the years 1991-19951993-1997 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%
Transit
Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
* As modified to reflect lowering of rate of return the Company was
seeking.
15
On July 10, 1995, the Company filed an application with
the PSC for an increase in retail electric rates. On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which willwas
designed to produce additional revenues, based on a test year, of
approximately $67.5 million annually. The increase will behas been
implemented in two phases. The first phase, an increase in
revenues of approximately $59.5 million annually based on a test year, or 6.47%,
commenced onin January 15, 1996. The second phase, will
be implementedan increase in January 1997 and will produce additional
revenues of approximately $8.0 million annually, or .87% more
than current rates., 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 substantially all (excluding accumulated
deferred income taxes)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. On October 27,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 which was
effective with the first billing cycle in November 1994 and is subject to annual review and
provides for the recovery of
approximately $16.2 million representing 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 1995,1997, as a result of the ongoing annual review,
the PSC approved the continued use ofCompany's request to increase the billing
surcharge. Thesurcharge from $.006 per therm to $.011 per therm which should
enable the Company to recover the remaining balance remaining to be recovered amounts to approximately $14.5 million.
Onof $29.6
million by December 2002.
In September 14, 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 onin October 5, 1992. The Company has
appealed the PSC's order to the Circuit Court. OnCourt, which in May 23, 1995 the Circuit Court
ordered the case back to the PSC for reconsideration of several
issues including the low-incomelow 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 filed, along withand
other intervenors filed another Petition for Reconsideration, which
the Supreme Court denied. The PSC and other intervenors filed
another appeal to the Circuit Court denied. Procedural matterswhich the Circuit Court denied
in an Order dated May 9, 1996. In this caseOrder, 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 yet to be resolved in the court.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 semiannuallyannually based on projected fuel costs for the ensuing
six-monthtwelve-month period, adjusted for any overcollection or
undercollection from the preceding six-monthtwelve-month period. The
Company has the right to request a formal proceeding at any time
should circumstances dictate such a review.
In the April 1995 semiannual1997 annual review of the fuel cost component of
electric rates, the PSC decreased the rate from 14.1613.10 mills per KWH
to 13.4812.85 mills per KWH, a monthly decrease of $.68$0.25 for an average
customer using 1,000 KWH a month. For the
October 1995 review the PSC continued the rate of 13.48 mills per
KWH.
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 19951997 review the PSC decreased the base cost of
gas from 51.05851.260 cents per therm to 43.08148.182 cents per therm which
resulted in a monthly decrease of $7.98$3.08 (including applicable
taxes) based on an average of 100 therms per month on a residential
bill during the heating season.
1617
ENVIRONMENTAL MATTERS
General
Federal and state authorities have imposed environmental
controlregulations 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 19931995 through 1995,1997, capital expenditures for
environmental control amounted to approximately $90.0$48.5 million. In
addition, approximately $10.4$17.1 million, $8.8$12.2 million and $7.4$10.4
million of environmental control expenditures were made during
1995, 19941997, 1996 and 1993,1995, respectively, which werewas 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 $10.1$48.0 million for 19961997 and $138.8$91.2
million for the four-year period 19971999 through 2000.2002. These
expenditures are included in the Company's construction program.
Air Quality Control
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 with DHEC byin 1995, and Phase II nitrogen oxide
requirements in December, 31, 1995.1997. The Company currently estimates
that air emissions control equipment will require capital
expenditures of $113$90.3 million over the 1996-20001998-2002 period to
retrofit existing facilities, with increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2005,2007, the Company
anticipates total capital expenditures of approximately $150$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 control
program.program in monitoring and
controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. The Company has been developing
compliance plans to meet this program.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.
1718
SuperfundComprehensive 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
estimates arean estimate is made of the cost,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 accruedactually 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 ten-yearfive-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 $18.0$32.4 million and $20.2$41.4 million at
December 31, 19951997 and 1994,1996, respectively. Estimates include, among other items,The deferral includes
the costs estimated to be associated with the matters discussed
in the
following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company has maintained an active review of the sites to monitor
the nature and extent of the residual contamination.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 Sitearea site in Charleston, South Carolina. This
site originally encompassedencompasses approximately eighteen30 acres and includedincludes properties
which were the locations for industrial operations, including a
wood preserving (creosote) plant, and one of the Company's
decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacentplants, properties owned by the
National Park Service and the City of Charleston and private
properties. The site has not been placed on the National
PriorityPriorities 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-cleanuppre-
cleanup site investigationsinvestigation 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. The1993 and the EPA
conditionally approved a Remedial Investigation Report in March
1997. Although the Company is also working withcontinuing 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 investigate potential
contaminationthe 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 may have
migratedcontain residues of by-product chemicals.
The Company is investigating the sites to monitor the city's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to
be responsible for a $43.5 million increase in costsnature
and extent of the aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes that it has meritorious defenses against this claim and
does not expect its resolution to have a material impact on its
financial position or results of operations.
The Company has been listed as a PRP and has recorded
liabilities, which are not material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina. The Company has
participated in de minimis buy-outs for the Aqua-Tech
Environmental Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina. The Company expects
to have no further involvement with these two sites.
The Arkansas Department of Pollution Control and Ecology has
identified the Company as a PRP for clean-up of PCBs at an
abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from the Department has been received. The
Company believes that its identification as a PRP was in error,
and that the resolution of this issue will not have a material
effect on the Company's results of operations or financial
position.
18residual 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 promulgatedproposed a proposal 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 millmil 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
over the life of Summer Station 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.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.
1920
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 594,000635,000
D-Area (3) Coal DOE Savannah
River Site, SC 1995 17,00035,000
Cope (4) Coal Cope, SC 1996 385,000408,000
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
Canadys Gas/Oil Canadys, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (5) Gas/Oil Parr, SC 1970 60,000
Williams (6)(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 (7) 3,722,000(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
Capacity Rating"Generating Capability" for this plant is expected average
hourly output. The lease which may be extended, expires on October 1, 2005.
(4) Plant began commercial operation in January 1996.
(5) Two of the four Parr gas turbines are leased and have a net
capability of 34,000 KW. This lease expires on June 29,
1996. The Company has agreed to purchase the leased
turbines on the lease expiration date.
(6) The two gas turbines at Williams are leased and have a net
capabilitywere purchased upon
expiration of 49,000 KW. Thisthe lease expires on June 29, 1997.
(7)(6) Excludes Williams Station.
2021
The Company owns 429428 substations having an aggregate
transformer capacity of 19,577,86821,356,393 KVA. The transmission system
consists of 3,0903,122 miles of lines and the distribution system
consists of 15,59616,129 pole miles of overhead lines and 3,1913,500 trench
miles of underground lines.
GAS
Natural Gas
The Company's gas system consists of approximately 6,833
miles of three-inch equivalent distribution pipelines and
approximately 11,26511,728
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 9861 motor coaches whichused 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 onthe
system for the City until a routeRegional 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 286fourteen routes covering 110 miles.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1.,
"BUSINESS - RATE MATTERS" and "BUSINESS - ENVIRONMENTAL MATTERS -
SuperfundComprehensive 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 STOCKEQUITY AND RELATED
SECURITY HOLDERSTOCKHOLDER MATTERS
All of the Company's common stock is owned by SCANA and
therefore there is no market for such stock. During 19951997 and 19941996
the Company paid $116.7$141.4 million and $115.1$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, 19951997 approximately $14.5$21.5
million of retained earnings were restricted as to payment of cash
dividends on common stock.
2122
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1997 1996 1995 1994 1993 1992 1991
Statement of Income Data (Thousands(Millions of Dollarsdollars, except statistics)
Operating Revenues $1,211,087 $1,181,274 $1,118,433 $ 994,381 $1,022,342$1,338 $1,345 $1,211 $1,181 $1,118
Operating Income 255,854 230,418 219,319 182,267 196,706282 286 256 230 219
Other Income 9,553 7,271 6,585 3,006 3,2839 4 9 7 7
Net Income 169,185 152,043 145,968 102,163 122,836195 190 169 152 146
Earnings Available for Common Stock 163,498 146,088 139,751 95,689 116,130186 185 163 146 140
Balance Sheet Data
Utility Plant, Net $3,157,657 $2,998,132 $2,687,193 $2,503,201 $2,380,761$4,457 $3,197 $3,158 $2,998 $2,687
Total Assets 3,802,433 3,587,091 3,189,939 2,890,953 2,748,5804,054 3,959 3,802 3,587 3,190
Capitalization:
Common equity 1,315,072 1,133,432 1,051,334 963,741 840,5051,447 1,413 1,315 1,133 1,051
Preferred stockStock (Not subject
to purchase or sinking funds) 26,027 26,027 26,027 26,027 26,027106 26 26 26 26
Preferred stock,Stock, Net (Subject to
purchase or sinking funds) 46,243 49,528 52,840 56,154 59,46912 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 1,279,379 1,231,191 1,097,043 945,964 993,674net 1,262 1,277 1,279 1,231 1,097
Total Capitalization $2,666,721 $2,440,178 $2,227,244 $1,991,886 $1,919,675$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
461,928 453,687
Territorial SalesTotal sales (Million KWH) 17,395 18,012 17,585 16,840 16,889 15,801 15,702
Residential:
Average annual use per customer (KWH) 13,214 14,149 13,859 13,048 14,077 13,037 13,246
Average annual rate per KWH $.0799 $.0785 $.0747 $.0743 $.0707
$.0695 $.0700Generating 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
218,582 214,485
Sales, excluding transportation
(Thousand Therms) 385,537 390,451 362,384 322,837 267,335 256,495 247,483
Residential:
Average annual use per customer (Therms) 531 639 570 538 606 577 522
Average annual rate per therm $.82 $.84 $.76$.86 $.74 $.77$.82 $.84 $.76
22
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 regulatory protection. Future deregulationregulation.
Deregulation of electric wholesale and retail markets will createis 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 utility'sCompany's strategic plan. The
Company has undertaken a variety of initiatives, including
reductions in operation and maintenance costs and in staffing
levels. In January 1996 the PSC approved (as discussed
under "Liquidity and Capital Resources")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. Such an eventAlthough 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 $116$236 million and $4$62 million of regulatory assets and
liabilities, respectively, excludingincluding amounts related
to net accumulatedrecorded for deferred
income tax assets and liabilities of approximately $33$118 million and
$52 million, respectively, on its balance sheet at December 31,
1995.1997.
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 demandsdemand 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 expandscontinues 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.
DueSCANA and Westvaco Corporation have formed a limited liability
company, Cogen South LLC, to continuing customer growth,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 Duke/Fluor Daniel in 1991 to design, engineer and
build a 385 MW coal-fired electric generating plant near Cope,
South Carolina.the Company for all its
electricity requirements at the North Charleston mill at the
Company's standard industrial rate. Construction of the plant
started in November
1992. Commercial operation began in January 1996.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 estimated
cost$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
Cope plant, excluding AFC, is $410.9 million. In
addition, the transmission lines for interconnection with the
Company's system are expected to cost $22.5 million.
On July 10, 1995environmental settlement, the Company filedhas agreed to construct an
application with1,100 space parking garage on the PSCCalhoun Park site and to transfer
the facility to the City in exchange for an increase in retail electric rates. On January 9, 1996a 20-year municipal bond
backed by revenues from the PSC issued an order grantingparking garage and a mortgage on the
Company an increase of 7.34%
which will produce additional revenues of approximately $67.5
million annually.parking garage. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 annually based on a test year, or 6.47%,
commenced on January 15, 1996. The second phase will be
implemented in January 1997 and will produce additional revenues
of approximately $8.0 million annually, or .87% more than current
rates. 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 substantially alltotal amount of the Company's electric
regulatory assets (excluding accumulated deferred income taxes)
andbond is not to exceed
$16.9 million, the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods
to allow recovery by the end of the year 2000.maximum expected project cost.
25
The Company's
request to shift approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved.
23
Therevised estimated primary cash requirements for 1996,1998,
excluding requirements for fuel liabilities and short-term
borrowings (includingand including notes payable to affiliated companies),companies, and
the actual primary cash requirements for 19951997 are as follows:
1996 1995
(Thousands1998 1997
(Millions of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $197,179 $250,870$175 $201
Nuclear fuel expenditures 21,147 21,04523 31
Maturing obligations, redemptions and
sinking and purchase fund requirements 21,197 15,81248 78
Total $239,523 $287,727$246 $310
Approximately 45%69% of total cash requirements (after payment of
dividends) was provided from internal sources in 19951997 as compared
to 22%65% in 1994.1996.
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, 19951997 the
Bond Ratio was 3.97.4.32. 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 $162.3$579 million at December 31,
1995)1997), (ii) retirements of Class A Bonds (which retirement credits
totaled $64.8$67.5 million at December 31, 1995)1997), and (iii) and cash on
deposit with the Trustee.
The Company has a newbond indenture (New Mortgage) 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, 1995)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, 19951997 the New Bond Ratio was 5.31.
The following financing transaction has occurred since
December 31, 1994:5.87.
On April 12, 199524, 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
$100$50 million of First Mortgage Bonds, 7 5/8% series due April 1, 20257.55% Trust Preferred Securities, Series A. The
Trust used the proceeds from the sale to repay short-term borrowings.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;
provided, however, that no such consent shall beis 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 indebtedness.debt. The FERC
hahas authorized the Company to issue up to $200$250 million of unsecured
promissory notes or commercial paper with maturity dates of
twelve months or less, but not later than December 31, 1997.
The1999.
26
At December 31, 1997 the Company had $165$315 million of
authorized and unusedlines 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, 1995.1997 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, theFuel Company has a credit
agreement for a maximum of $125 million with the full amount
available at December 31, 1995.1997. 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, 19951997 was
$76.8 million.
24
$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, 19951997 the
Preferred Stock Ratio was 2.58.2.69.
The Company anticipates that its 19961998 cash requirements of
$378.9$389.6 million will be met through internally generated funds
(approximately 77%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-
termlong-term
indebtedness. The timing and amount of such financing will
depend upon market conditions and other factors. Actual 1996
expenditures may vary from the estimates set forth above due to
factors such as inflation and economic conditions, regulation and
legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.
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.
By December 31, 1995 theThe Company had filed with DHEC compliance plans related to Phase
II sulfur dioxide requirements with DHEC.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 $113$90.3 million over the 1996-20001998-2002 period to
retrofit existing facilities, with increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2005,2007, the Company
anticipates total capital expenditures of approximately $150$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 SCE&G'sthe Company's and GENCO's generating
units. Concurrent with renewal of these permits, the permitting
agency has implemented a more rigorous control programs.program in monitoring and
controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. The Company has been developing
compliance plans for this program.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.
2527
The Company has an environmental assessment program to
identify and assess current and former operations sites that could
require environmental cleanup. As site assessments are initiated
estimates arean estimate is made of the cost,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 accruedactually 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 ten-yearfive-year period for
electric operations and an eight-
yeareight-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 $18.0$32.4 million and $20.2$41.4 million at
December 31, 19951997 and 1994,1996, respectively. Estimates include, among other items,The deferral includes
the estimated costs associated with the matters discussed in the following
paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.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 Sitearea site in Charleston, South Carolina. This
site originally encompassedencompasses approximately eighteen30 acres and includedincludes properties
which were the locations for industrial operations, including a
wood preserving (creosote) plant, and one of the Company's
decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacentplants, properties owned by the
National Park Service and the City of Charleston and private
properties. The site has not been placed on the National
PriorityPriorities 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-cleanuppre-
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. The1993 and the EPA
conditionally approved a Remedial Investigation Report in March
1997. Although the Company is also working withcontinuing 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
investigate
potential contaminationthe 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 may
have migratedcontain residues of by-product chemicals.
The Company is investigating the sites to monitor the City's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to
be responsible for a $43.5 million increase in costsnature
and extent of the aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes it has meritorious defenses against this claim and does
not expect its resolution to have a material impact on its
financial position or results of operations.residual contamination.
Regulatory Matters
The Company filed for electric rate relief in 1995 to
encompass primarily the remaining costs of completing the Cope
Generating Station. As discussed under "Liquidity and Capital
Resources,"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 9, 1996 increasing1996. 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 retail rates.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 are likely to bewere impacted by
the NEPA and FERC OrderOrders No. 636.636 and 888. NEPA iswas 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 iswas 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 willcontinues
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 its operations, itscash flows, financial
position or its business prospects.
26
Statements of Financial Accounting Standards To Be AdoptedOther
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." The provisions of the Statement, which will be
implemented by the Company for the fiscal year beginning January
1, 1996, require the recognition of a loss in the income
statement and related disclosures whenever events or changes in
circumstances indicate that the carrying amount of a long-lived
asset may not be recoverable. The Company does not believe that
adoption of the provisions of the Statement will2000 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 financial position.cash flows.
The Financial Accounting Standards Board issued StatementCompany also has begun evaluating embedded processors
located in field operations areas for the purpose of Financial Accounting Standards No. 123, "Accountingidentifying
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 Stock-
Based Compensation,"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 implementedtimely converted. A failure to
convert by another company, or a conversion that is incompatible
with the CompanyCompany's systems, could have material adverse effect on
January 1, 1996. The Company does not believe that adoption of
the provisions of the Statement will have a material impact on
its results of operations, financial position or financial position.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 1995, 19941997, 1996 and 19931995 were as follows:
1997 1996 1995
1994 1993(Millions of Dollars)
Net income $169,185 $152,043 $145,968$194.7 $190.5 $169.2
Percent increase (decrease) in net
income 2.19% 12.59% 11.27%
4.16% 42.9%
19951997 Net income increased for the year primarily due toas a result
of increases in electric and gas margins and lower operating
and maintenance expenses which more than offset increases
in fixed costs.
1994sales margins.
1996 Net income increased for the year primarily due to an
increaseas a result
of increases in the electric marginand gas sales margins which
more than offset increases in operating expenses.
The Company's financial statements include an allowance for
funds used during construction (AFC).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 7.9 %4.0%
of income before income taxes in 1995, 6.3%1997, 3.2% in 19941996 and 5.6%7.9% in
1993.
27
1995.
Electric Operations
Electric sales margins for 1995, 19941997, 1996 and 19931995 were as
follows:
1997 1996 1995 1994 1993
(Millions of Dollars)
Electric revenues $1,103.1 $1,106.7 $1,006.6 $974.3 $940.2
(Provision) for rate refunds - 1.2 0.3
Net Electric operating revenues 1,006.6 975.5 940.5
Less: Fuel used in electric generation 181.0 187.1 177.6 176.6 164.2
Purchased power 109.2 106.8 98.2 112.9 111.1
Margin $ 813.0 $ 812.8 $ 730.8
$686.0 $665.2
1995, 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 combined impact of
warmer weather in the third quarter of 1995, colder
weather in the fourth quarter of 1995 and the base rate increase
received by the Company in mid-1994. These
factors more than offset the negative impact of milder
weather experienced during the first half of 1995. An
increase of 7,943 electric customers to 484,381 total
customers contributed to an all-time peak demand record of
3,683 MW set on August 14, 1995.
1994 The electric sales margin increased over the prior
year primarily as a result of an increase in retail
electric rates phased in over a two-year period beginning
in June 1993January 1996 and an increase in industrial sales which
more than offset the negative impact of a six percent
decrease in residential sales of electricity due to milder
weather in 1994.economic
growth factors.
Increases (decreases) from the prior year in megawatt hourmegawatt-hour
(MWH) sales volume by classes were as follows:
Classification 1995 19941997 1996
Residential 415,676 (339,620)(292,518) 212,888
Commercial 229,565 4,198100,324 144,536
Industrial 48,651 274,467
Sale113,717 110,147
Sales for Resale (excluding interchange) 38,688 18,408(538,005) (39,853)
Other 12,776 (6,907)15 (1,013)
Total territorial 745,356 (49,454)
Interchange 24,545 (27,013)(616,467) 426,705
Negotiated Market Sales Tariff 564,081 699,425
Total 769,901 (76,467)(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 1995, 19941997, 1996 and 19931995 were as follows:
1997 1996 1995 1994 1993
(Millions of Dollars)
Gas operating revenues $233.6 $234.8 $200.6 $201.7 $174.0
Less: Gas purchased for resale 151.9 157.1 125.0 127.8 107.7
Margin $ 81.7 $ 77.7 $ 75.6
$ 73.9 $ 66.3
1995, 1997 The gas sales margin increased over the prior year primarily as a result of
increases in interruptible gas
sales.
1994higher margins and sales tointerruptible customers.
, 1996 The gas sales margin increased over the prior year primarily as a result of
increases in interruptible
gasincreased firm sales.
28
Increases (decreases) from the prior year in dekatherm (DT) sales volume
by classes, including transportation gas, were as follows:
Classification 1995 19941997 1996
Residential 802,211 (477,886)(2,188,215) 1,774,289
Commercial 623,533 970,726(123,385) 590,843
Industrial 2,528,974 5,057,4041,820,166 441,571
Transportation gas (1,866,414) (1,524,089)(430,610) (495,256)
Total 2,088,304 4,026,155(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 1995 19941997 1996
(Millions of Dollars)
Other operation and maintenance $(7.8) $ 3.93.0 $22.3
Depreciation and amortization 10.6 5.74.7 17.4
Income taxes 12.9 2.8(9.7) 10.8
Other taxes 5.1 5.08.1 3.2
Total $20.8 $17.4
1995$ 6.1 $53.7
, 1997 Other operation and maintenance expenses decreased
primarily as a resultincreased
somewhat from 1996 levels. A decrease in transit operating
costs resulting from the Company's
transfer of lower pension costs and lowerthe ownership of the Charleston transit
system to the City of Charleston in October 1996 largely
offset increases in costs at electric generating stations.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 and the
expensing of software costs.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 partially
offset by lower payroll taxes resulting from early
retirements of employees.
1994 Other operation and maintenance expenses increased
primarily due to an increase in the costs of postretirement
benefits other than pensions. These costs are accrued in
accordance with Financial Accounting Standards Board
Statement No. 106. (See Note 1K of Notes to Consolidated
Financial Statements.) The increase in depreciation and
amortization expenses is attributable to property additions
and to increases in depreciation rates. The increase in
other taxes reflects an increase in property taxes of
approximately $5 million.assessments.
Interest Expense
Increases (decreases) in interest expense were as follows:
Classification 1995 1994
(Millions of Dollars)
Interest on long-term debt, net $11.0 $8.0
Other interest expense 4.1 (.6)
Total $15.1 $7.4
1995 The increase in interest expense, excluding the debt
component of AFC, iswere 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 $(3.2)
There was no material change in interest expense from 1996 to
1997. The decrease in interest expense from 1995 to 1996 was due
primarily to reductions in outstanding debt throughout most of the
issuance of
additional debt including commercial paper duringyear.
32
PAGE 33
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the latter
part of 1994 and early 1995.
1994Company described below
are held for purposes other than trading.
Interest rate risk - The increasetable below provides information
about the Company's financial instruments that are sensitive to
changes in interest expense, excludingrates. For debt obligations, the debt
componenttable
presents principal cash flows and related weighted average interest
rates by expected maturity dates.
December 31, 1997
Expected Maturity Date
(Millions of AFC, is primarily attributableDollars)
There- Fair
Liabilities 1998 1999 2000 2001 2002 after Total Value
Long-Term Debt:
Fixed Rate ($) 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 issuanceCompany's Subsidiary Trust, SCE&G Trust I
holding solely $50 million, principal amount of $100 million7.55%
of First Mortgage Bonds in JulyJunior Subordinated Debentures of the Company, due 2027 50 -
Long-Term Debt, Net (Notes 3, 4 and $30 million
of Pollution Control Facilities Revenue Bonds in November,
both to finance utility construction,8) 1,262 1,277
Total Capitalization 2,877 2,759
Current Liabilities:
Short-term borrowings (Notes 8 and to the issuance9) 13 90
Current portion of long-term debt during 1993.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report....................................... 31
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1995(Note 3) 48 43
Accounts payable 53 67
Accounts payable - affiliated companies (Notes 1 and 1994...3) 32 Consolidated Statements of Income32
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 Retained Earnings7) 539 522
Deferred investment tax credits (Notes 1 and 7) 89 75
Reserve for the years ended December 31, 1995, 1994nuclear plant decommissioning (Note 1) 49 42
Postretirement benefits 61 37
Other (Note 1) 145 146
Total Deferred Credits 883 822
Commitments and 1993............. 34
Consolidated Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993............................. 35
Consolidated Statements of Capitalization as of
December 31, 1995 and 1994................................... 36Contingencies (Note 10) - -
Total $4,054 $3,959
See Notes to Consolidated Financial Statements..................... 38
Supplemental financial statement schedules are omitted because ofStatements.
36
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For 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.
30
INDEPENDENT AUDITOR'S 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 ofYears Ended December 31, 1997 1996 1995
(Millions of Dollars)
Operating Revenues (Notes 1 and 19942):
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 the
related Consolidated Statementsamortization (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 andat Beginning of Year 415 366 324
Common Stock Cash Flows for eachDividends Declared (Note 5) (163) (136) (121)
Retained Earnings at End of the three years in the period ended
December 31, 1995. 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, 1995 and 1994 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1995 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 1996
31
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1995 1994
(Thousands of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $3,277,530 $3,165,391
Gas 320,847 307,929
Transit 3,768 3,785
Common 91,616 77,327
Total 3,693,761 3,554,432
Less accumulated depreciation and amortization 1,196,279 1,171,758
Total 2,497,482 2,382,674
Construction work in progress 613,683 571,867
Nuclear fuel, net of accumulated amortization 46,492 43,591
Utility Plant, Net 3,157,657 2,998,132
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 11,603 11,931
Current Assets:
Cash and temporary cash investments (Note 8) 6,798 346
Receivables - customer and other 154,816 127,679
Receivables - affiliated companies (Note 1) 7,132 18,121
Inventories (At average cost):
Fuel (Notes 1, 3 and 4) 35,812 31,310
Materials and supplies 43,583 43,228
Prepayments 10,158 14,389
Accumulated deferred income taxes 19,420 17,931
Total Current Assets 277,719 253,004
Deferred Debits:
Emission allowances 28,514 19,409
Unamortized debt expense 11,445 11,690
Unamortized deferred return on plant investment (Notes 1 and 2) 6,369 10,614
Nuclear plant decommissioning fund (Note 1) 36,070 30,383
Other (Note 1) 273,056 251,928
Total Deferred Debits 355,454 324,024
Total $3,802,433 $3,587,091
32
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1995 1994
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment:
Common equity (Note 5) $1,315,072 $1,133,432
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,341,099 1,159,459
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 46,243 49,528
Long-Term Debt, Net (Notes 3, 4 and 8) 1,279,379 1,231,191
Total Capitalization 2,666,721 2,440,178
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 80,500 100,000
Notes payable - affiliated companies - 19,409
Current portion of long-term debt (Note 3) 36,033 33,042
Current portion of preferred stock (Note 6) 2,439 2,418
Accounts payable 71,731 61,466
Accounts payable - affiliated companies (Notes 1 and 3) 26,212 33,357
Customer deposits 12,518 12,668
Taxes accrued 64,008 46,646
Interest accrued 21,626 21,534
Dividends declared 33,126 28,489
Other 12,507 15,525
Total Current Liabilities 360,700 374,554
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 488,310 503,723
Accumulated deferred investment tax credits (Notes 1 and 7) 78,316 81,546
Accumulated reserve for nuclear plant decommissioning (Note 1) 36,070 30,383
Other (Note 1) 172,316 156,707
Total Deferred Credits 775,012 772,359
Commitments and Contingencies (Note 10) - -
Total $3,802,433 $3,587,091
See Notes to Consolidated Financial Statements.
33
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1995 1994 1993
(Thousands of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $1,006,566 $ 975,526 $ 940,547
Gas 200,632 201,746 174,035
Transit 3,889 4,002 3,851
Total Operating Revenues 1,211,087 1,181,274 1,118,433
Operating Expenses:
Fuel used in electric generation 177,579 176,581 164,187
Purchased power (including affiliated
purchases)(Note 1) 98,231 112,900 111,111
Gas purchased from affiliate for resale (Note 1) 125,032 127,846 107,722
Other operation 211,318 214,344 207,126
Maintenance 53,071 57,801 61,107
Depreciation and amortization (Note 1) 117,584 106,952 101,220
Income taxes (Notes 1 and 7) 96,956 84,066 81,280
Other taxes (Note 12) 75,462 70,366 65,361
Total Operating Expenses 955,233 950,856 899,114
Operating Income 255,854 230,418 219,319
Other Income (Note 1):
Allowance for equity funds used during construction 9,499 7,989 7,496
Other income (loss), net of income taxes 54 (718) (911)
Total Other Income 9,553 7,271 6,585
Income Before Interest Charges 265,407 237,689 225,904
Interest Charges (Credits):
Interest on long-term debt, net 98,361 87,361 79,410
Other interest expense (Notes 1 and 3) 9,324 5,189 5,812
Allowance for borrowed funds used
during construction (Note 1) (11,463) (6,904) (5,286)
Total Interest Charges, Net 96,222 85,646 79,936
Net Income 169,185 152,043 145,968
Preferred Stock Cash Dividends (At stated rates) (5,687) (5,955) (6,217)
Earnings Available for Common Stock 163,498 146,088 139,751
Retained Earnings at Beginning of Year 324,101 291,713 262,262
Common Stock Cash Dividends Declared (Note 5) (121,363) (113,700) (110,300)
Retained Earnings at End of Year $ 366,236 $ 324,101 $ 291,713
See Notes to Consolidated Financial Statements.
34
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995 1994 1993
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $169,185 $152,043 $145,968
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 117,839 107,103 101,370
Amortization of nuclear fuel 20,017 13,487 18,156
Deferred income taxes, net (17,632) 13,133 56,982
Deferred investment tax credits, net (3,230) (2,901) (3,245)
Net regulatory asset arising from adoption of SFAS No. 109 13,560 (1,985) (40,398)
Allowance for funds used during construction (20,962) (14,893) (12,782)
Unamortized loss on reacquired debt (3,325) (129) (17,094)
Early retirements (24,823) (7,086) (11,840)
Nuclear refueling accrual 6,957 (4,881) (6,086)
Over (under) collections, fuel adjustment clause 18,986 (17,965) (13,728)
Emission allowances (9,105) (19,409) -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (16,148) (26,260) (27,920)
(Increase) decrease in inventories (4,857) 26 1,401
Increase (decrease) in accounts payable 3,120 (430) 16,757
Increase (decrease) in estimated rate
refunds and related interest - (2,509) (15,302)
Increase (decrease) in taxes accrued 17,362 6,681 (11,162)
Increase (decrease) in interest accrued 92 3,770 (8,669)
Other, net (14,623) 14,106 8,002
Net Cash Provided From Operating Activities 252,413 211,901 180,410
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, net of AFC (271,804) (406,054) (287,838)
Nonutility property and investments (111) (287) (248)
Transfer of assets from SCANA - 6,285 -
Net Cash Used For Investing Activities (271,915) (400,056) (288,086)
Cash Flows From Financing Activities:
Proceeds:
Issuance of notes payable - affiliated company - 19,409 -
Issuance of mortgage bonds 99,583 99,207 592,884
Issuance of pollution control bonds - 30,000 -
Equity contributions from parent 139,505 43,426 58,142
Other long-term debt 2,543 11,200 2,562
Repayments:
Notes payable - affiliated company (19,409) - -
Mortgage bonds (64,779) - (430,000)
Other long-term debt (12,548) (1,662) (405)
Preferred stock (3,264) (3,398) (3,295)
Dividend Payments:
Common stock (116,663) (115,100) (108,641)
Preferred stock (5,750) (6,048) (6,247)
Short-term borrowings, net (19,500) 98,989 978
Fuel and emission allowance financings, net 26,236 13,844 (18,948)
Advances - affiliated companies, net - (1,559) (3,463)
Net Cash Provided From Financing Activities 25,954 188,308 83,567
Net Increase (Decrease) in Cash and Temporary Cash Investments 6,452 153 (24,109)
Cash and Temporary Cash Investments, January 1 346 193 24,302
Cash and Temporary Cash Investments, December 31 $ 6,798 $ 346 $ 193
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $11,463, $6,904 and $5,286) $105,537 $ 87,255 $ 92,367
- Income taxes 95,827 77,295 79,612
Noncash Financing Activities:
Department of Energy decontamination and decommissioning
fund obligation - - 4,965
See Notes to Consolidated Financial Statements.
35
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1995 1994
Common Equity (Note 5): (Thousands of Dollars)
Common Stock, $4.50 par value, authorized 50,000,000 shares; issued
and outstanding, 40,296,147 shares $ 181,333 $181,333
Premium on common stock 395,072 395,072
Other paid-in capital 377,822 238,369
Capital stock expense (5,391) (5,443)
Retained earnings 366,236 324,101
Total Common Equity 1,315,072 49% 1,133,432 47%
Cumulative Preferred Stock (Not subject to purchase or sinking funds):
$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
$100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767
$50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260
Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 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 1995 1994 Current Through Minimum
7.70% 86,965 89,984 101.00 - 101.00 8,696 8,998
8.12% 123,045 126,835 102.03 - 102.03 12,305 12,684
Total 210,010 216,819
$50 Par Value - Authorized 1,614,405 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
4.50% 17,519 19,088 51.00 - 51.00 876 954
4.60% 834 2,334 50.50 - 50.50 42 117
4.60%(A) 26,052 28,052 51.00 - 51.00 1,303 1,403
4.60%(B) 74,800 78,200 50.50 - 50.50 3,740 3,910
5.125% 72,000 73,000 51.00 - 51.00 3,600 3,650
6.00% 83,200 86,400 50.50 - 50.50 4,160 4,320
8.72% 95,985 127,956 51.00 12-31-98 50.00 4,799 6,398
9.40% 183,219 190,245 51.175 - 51.175 9,161 9,512
Total 553,609 605,275
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1995 and 1994
Total Preferred Stock (Subject to purchase or sinking funds) 48,682 51,946
Less: Current portion, including sinking fund requirements 2,439 2,418
Total Preferred Stock, Net (Subject to purchase or sinking funds) 46,243 2% 49,528 2%
36
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1995 1994
(Thousands of Dollars)
Long-Term Debt (Notes 3, 4 and 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100,000 100,000
6 1/4% 2003 100,000 100,000
7.70% 2004 100,000 100,000
7 1/8% 2013 150,000 150,000
7 1/2% 2023 150,000 150,000
7 5/8% 2023 100,000 100,000
7 5/8% 2025 100,000 -
First and Refunding Mortgage Bonds:
Year of
Series Maturity
4 7/8% 1995 - 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
7 1/4% 2002 30,000 30,000
9% 2006 130,771 145,000
8 7/8% 2021 120,450 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,560 6,660
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365
Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 30,000
Department of Energy Decontamination and Decommissioning Obligation 3,560 3,922
Commercial Paper 76,830 61,794
Other 3,993 3,294
Total Long-Term Debt 1,319,649 1,269,155
Less: Current maturities, including sinking fund requirements 36,033 33,042
Unamortized discount 4,237 4,922
Total Long-Term Debt, Net 1,279,379 48% 1,231,191 50%
Total Capitalization $2,666,721 100% $2,440,178 100%Year $ 438 $ 415 $ 366
See Notes to Consolidated Financial Statements.
37
NOTES TO
SOUTH CAROLINA ELECTRIC & GAS COMPANY
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, through wholly owned subsidiaries is predominately
engaged inCASH FLOWS
For 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 and South Carolina Fuel Company, Inc.
(Fuel Company). (See Note 1N.) Intercompany balances and
transactions between the Company and Fuel Company 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
atYears 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 1994 the Company had approximately $17.5
million and $16.3 million, respectively, payable to Pipeline
Corporation for such gas purchases. The Company purchases allamortization 140 135 118
Amortization of the electric generation of Williams Station, which is owned by
GENCO, under a unit power sales agreement. At December 31, 1995
and 1994 the Company had approximately $8.2 million and $8.8
million, respectively, payable to GENCO for unit power purchases.
Such unit power purchases, which are included in "Purchased
power," amounted to approximately $83.5 million, $92.8 million
and $98.1 million in 1995, 1994 and 1993, respectively.
Total interestnuclear fuel 19 19 20
Deferred income based on market interest rates,
associated with the Company's advances to affiliated companies
was approximately $174,000, $5,000 and $143,000 in 1995, 1994 and
1993, respectively.
Included in "Other interest expense" for 1995, 1994 and 1993
is approximately $114,000, $279,000 and $29,000, respectively,
relating to advances from affiliated companies. Intercompany
interest is calculated at market rates.
B. Basis of Accounting
The Company prepares its financial statements in accordance
with the provisions of Statement of Financial Accounting
Standards No. 71 (SFAS 71), "Accounting for the Effects of
Certain Types of Regulations." The accounting standard allows
cost-based rate-regulated utilities, such as the Company, 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, 1995, approximately $116 million and $4 million of
regulatory assets and liabilities, respectively, excludingtaxes, net accumulated deferred income tax assets of approximately $33
million. As discussed in Note 2A, the PSC has approved
accelerated recovery of substantially all of the Company's
electric regulatory assets (approximately $84.8 million). 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.
C. System of Accounts
The accounting records of the Company are maintained in
accordance with the Uniform System of Accounts prescribed by the
FERC and as adopted by the PSC.
38
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 allowance16 32 (18)
Pension asset (24) (23) (15)
Postretirement benefits 24 16 8
Allowance for funds used during construction are added to utility plant accounts. The original
cost(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 utilityAFC (232) (209) (273)
(Increase) decrease in nonutility property retired or otherwise disposedand investments (5) - -
Net Cash Used For Investing Activities (237) (209) (273)
Cash Flows From Financing Activities:
Proceeds:
Issuance of is
removedmortgage bonds and other long-term debt 1 - 103
Issuance of company - obligated mandatorily
redeemable trust preferred securities 49 - -
Equity contributions from utility plant accountsparent 12 49 140
Issuance of preferred stock 99 - -
Repayments:
Notes payable - affiliated company - - (19)
Mortgage bonds and generally charged, along
with the costother long-term debt (15) (23) (78)
Preferred stock (53) (3) (3)
Repayment of removal, less salvage, to accumulated
depreciation. The costs of repairs, replacementsBank Loans (10) (3) -
Dividend Payments:
Common stock (141) (133) (117)
Preferred stock (9) (5) (6)
Short-term borrowings, net (77) 10 (20)
Fuel 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 Summer Stationemission allowance financings, net 14 (11) 26
Net Cash Provided From Financing Activities (130) (119) 26
Net Increase (Decrease) in Cash and PSA are
joint owners of Summer Station in the proportions of two-thirdsTemporary Cash Investments 1 (1) 7
Cash and one-third, respectively. The parties share the operating
costsTemporary Cash Investments, January 1 5 6 -
Cash 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 $925.1 million and $923.1 million as ofTemporary Cash Investments, December 31 1995$ 6 $ 5 $ 7
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $6, $5 and 1994, respectively. Accumulated depreciation
associated with the Company's share of Summer Station was
approximately $261.0 million and $297.9 million as of$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, 19951997 1996
Common Equity (Note 5): (Millions of Dollars)
Common stock, 4.50 par value, authorized 50,000,000 shares; issued
and 1994, respectively. (See Note 2A.) 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 ofoutstanding, 40,296,147 shares $ 181 $ 181
Premium on common stock 395 395
Other paid-in 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 8.6%, 8.5% and 9.4% for 1995, 1994 and 1993,
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. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that
date, the Company ceased the deferral of carrying costs
associated with 400 MW of electric generating capacity previously
removed from rate base and began amortizing the accumulated
deferred carrying costs on a straight-line basis over a ten-year
period. Amortization of deferred carrying costs, included in
"Depreciation and amortization," was approximately $4.2 million
for each of 1995, 1994 and 1993.
G. 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 semiannual 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 semiannual fuel cost hearing. The Company had
overcollected through the electric fuel cost component
approximately $3.8 million at December 31, 1995 and
undercollected approximately $3.5 million at December 31, 1994
which are included in "Deferred Credits - Other" and "Deferral
Debits - Other," respectively.
Customers438 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 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 costpurchase 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 that contained8):
$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 the rates is deferred1997 and included
when establishing gas costs during the next annual gas cost
recovery hearing. At December 31, 1995 and 1994 the1996
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 had
undercollected through the gas cost recovery procedure
approximately $4.6 million and $16.3 million, respectively, which
are included in "Deferred Debits - Other."
39
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.
H. 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 3.02%, 3.01%,
and 2.97% for 1995, 1994 and 1993, respectively.
Nuclear fuel amortization, which is included in "Fuel used
in electric generation" and is recovered through the fuel cost
componentObligated Mandatorily Redeemable Preferred
Securities 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 United
States DOE under a contract for disposal of spent nuclear fuel.
I. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
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 $545.3Subsidiary Trust, SCE&G Trust I,
holding solely $50 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 each of
1995 and 1994) are used to purchase insurance policies on the
lives of certain Company personnel. Through the purchase of
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.
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the
electric utility industry regarding the recognition, measurement
and classification of decommissioning costs for the financial
statements of electric utilities with nuclear generating
facilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting
for removal costs, including decommissioning. If the current
electric utility industry accounting practices for such
decommissioning are changed: (1) annual provisions for
decommissioning could increase, and (2) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction of decommissioning
expense.
Pursuant to the NEPA passed by Congress in 1992, the Company
has recorded a liability for its estimated share of amounts
required by the DOE for its decommissioning fund. The liability,
approximately $3.6 million at December 31, 1995, has been
included in "Long-Term Debt, Net." The Company will recover 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."
J. Income Taxes
The Company is included in the consolidated Federal income
tax return filed by SCANA. Income taxes are allocated to the
Company based on its contribution to the consolidated total.
As required by Statement of Financial Accounting Standards
No. 109, 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.
40
K. Pension Expense
The Company participates in SCANA's noncontributory defined
benefit pension plan, which covers all permanent Company
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
pension costs accrued 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,
1995, 1994 and 1993 included the following components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 5,187 $ 8,684 $ 7,629
Interest cost on projected benefit obligation 19,473 21,711 20,413
Adjustments:
Return on plan assets (103,874) 2,365 (50,389)
Net amortization and deferral 74,769 (29,760) 25,936
Amounts contributed by the Company's
affiliates (203) (130) (175)
Net periodic pension (income) expense $ (4,648) $ 2,870 $ 3,414
The determination of net periodic pension cost is based upon
the following assumptions:
1995 1994 1993
Annual discount rate 8.0% 7.25% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 2.5% 4.75% 5.5%
The following table sets forth the funded status of the plan
at December 31, 1995 and 1994:
1995 1994
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $228,434 $205,364
Nonvested benefit obligation 15,540 13,966
Accumulated benefit obligation $243,974 $219,330
Plan assets at fair value
(invested primarily in equity and debt securities) $447,760 $347,702
Projected benefit obligation 284,145 246,318
Plan assets greater than
projected benefit obligation 163,615 101,384
Unrecognized net transition liability 9,022 11,307
Unrecognized prior service costs 9,660 9,374
Unrecognized net gain (146,943) (102,284)
Pension asset recognized in
Consolidated Balance Sheets $ 35,354 $ 19,781
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 1995 and
1994.
1995 1994
Annual discount rate used to determine
benefit obligations 7.5% 8.0%
Assumed annual rate of future salary increases
for projected benefit obligation 3.0% 2.5%
41
The change in the annual discount rate used to determine
benefit obligations from 8.0% to 7.5% and the change in the
expected salary increase rate from 2.5% to 3.0% as of December
31, 1995 increased the projected benefit obligation and decreased
the unrecognized net gain by approximately $28.6 million.
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. Prior to 1993, the Company expensed these benefits,
which are primarily health care, as claims were incurred. In its
June 1993 electric rate order, the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. The Company expensed approximately $8.5 million and
$8.6 million, net of payments to current retirees, for the years
ended December 31, 1995 and 1994, respectively. The PSC has
authorized accelerated amortization of the Company's remaining
transition obligation for postretirement benefits other than
pensions related to electric operations. (See Note 2A.)
Net periodic postretirement benefit cost for the years ended
December 31, 1995, 1994 and 1993, included the following
components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 2,076 $ 2,417 $ 1,908
Interest cost on accumulated postretirement
benefit obligation 7,253 6,644 5,502
Adjustments:
Return on plan assets - - -
Amortization of unrecognized
transition obligation 3,344 3,344 3,344
Other net amortization and deferral 661 860 -
Amounts contributed by the Company's affiliates (610) (575) (525)
Net periodic postretirement benefit cost $12,724 $12,690 $10,229
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1995 1994 1993
Annual discount rate 8.0% 7.25% 8.0%
Health care cost trend rate 11.0% 11.25% 13.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 6.0% 5.25% 6.0%
42
The following table sets forth the funded status of the plan
at December 31, 1995 and 1994:
1995 1994
(Thousands of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 64,989 $ 59,174
Other fully eligible participants 6,685 4,995
Other active participants 27,076 24,889
Accumulated postretirement benefit obligation 98,750 89,058
Plan assets at fair value - -
Plan assets less accumulated postretirement benefit
obligation (98,750) (89,058)
Unrecognized net transition liability 58,237 61,581
Unrecognized prior service costs 5,320 3,453
Unrecognized net loss 13,840 11,156
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(21,353) $(12,868)
The accumulated postretirement benefit obligation is based upon the
plan's benefit provisions and the following assumptions:
1995 1994
Assumed health care cost trend rate used to
measure expected costs 10.5% 12.0%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.5% 6.0%
Annual discount rate 7.5% 8.0%
Annual rate of salary increases 3.0% 2.5%
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, 1995
and the accumulated postretirement benefit obligation as of
December 31, 1995 would be to increase such amounts by $203,000
and $3.4 million, respectively.
L. Debt Premium, Discount and Expense, Unamortized Loss on
Reacquired Debt
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.
M. Environmental
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of theprincipal 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 and
accrued 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 ten-year period for
electric operations and an eight-year period for gas operations.
Such deferred amounts totaled $18.0 million and $20.2 million at
December 31, 1995 and 1994, respectively, and are included in
"Deferred Debits - Other."
43
N. 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
financing7.55% 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.)
O. 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.
P. Recently Issued Accounting Standards
The Financial Accounting Standards Board has issued
Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of." The provisions of the Statement, which
will be implemented by the Company for the fiscal year beginning
January 1, 1996, require the recognition of a loss in the income
statement and related disclosures whenever events or changes in
circumstances indicate that the carrying amount of a long-lived
asset may not be recoverable. The Company does not believe that
adoption of the provisions of the Statement will have a material
impact on its results of operations or financial position.
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-
Based Compensation," which will be implemented by the Company on
January 1, 1996. The Company does not believe that adoption of
the provisions of the Statement will have a material impact on
its results of operations or financial position.
Q. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1995 presentation.
R. 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.
44
2. RATE MATTERS:
A. On July 10, 1995, the Company filed an application with
the PSC for an increase in retail electric rates. On January 9,
1996 the PSC issued an order granting the Company an increase of
7.34% which will produce additional revenues of approximately
$67.5 million annually. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 million annually based on a test year, or
6.47%, commenced on January 15, 1996. The second phase will be
implemented in January 1997 and will produce additional revenues
of approximately $8.0 million annually, or .87% more than current
rates. 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 and collected through rates over a
ten-year period. Additionally, the PSC approved accelerated
recovery of substantially all (excluding accumulated deferred
income taxes) of the Company's electric regulatory assets and the
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
approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved.
B. On October 27, 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, which was
effective with the first billing cycle in November 1994 and is
subject to annual review, provides for the recovery of
approximately $16.2 million representing substantially all site
assessment and cleanup costs for the Company's gas operations
that had previously been deferred. In October 1995, as a result
of the ongoing annual review, the PSC approved the continued use
of the billing surcharge. The balance remaining to be recovered
amounts to approximately $14.5 million.
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
on May 23, 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. Another Petition for Reconsideration was
filed by the PSC and other intervenors, which was denied by the
Circuit Court. Procedural matters in this case are yet to be
resolved in the court.
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 1996 through 2000
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1996 $ 36,033 1999 $ 17,663
1997 33,252 2000 117,668
1998 114,483
Approximately $17.3 million of the portion of long-term debt
payable in 1996 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.
45
The Company has three-year revolving lines of credit
totaling $100 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 $100 million. The long-term
nature of the lines of credit allow commercial paper in excess of
$100 million to be classified as long-term debt. The Company had
outstanding commercial paper of $111.2 million at December 31,
1994, of which $11.2 million was reclassified to long-term debt.
Certain outstanding long-term debt of an affiliated
company (approximately $35.9 million at both December 31, 1995
and 1994) is guaranteed by the Company.
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 July 31, 1998. 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 $76.8 million and $50.6
million at December 31, 1995 and 1994 at weighted average
interest rates of 5.76% and 6.06%, respectively.
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including
Preferred Stock Not Subject to Purchase or Sinking Funds) during
1995, 1994 and 1993 are summarized as follows:
Common Preferred Thousands
Shares Shares of Dollars
Balance December 31, 1992 40,296,147 322,877 $989,768
Changes in Retained Earnings:
Net Income 145,968
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,217)
Common Stock (110,300)
Equity Contributions from Parent 58,142
Balance December 31, 1993 40,296,147 322,877 1,077,361
Changes in Retained Earnings:
Net Income 152,043
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,955)
Common Stock (113,700)
Equity Contributions from Parent 49,710
Balance December 31, 1994 40,296,147 322,877 1,159,459
Changes in Retained Earnings:
Net Income 169,185
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,687)
Common Stock (121,363)
Equity Contributions from Parent
including transfer of assets 139,505
Balance December 31, 1995 40,296,147 322,877 $1,341,099
46
The Restated Articles of IncorporationJunior 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 the Indenture
underlying its8):
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 contain provisions that under
certain circumstances could limit the paymentBonds:
Year 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, 1995 approximately $14.5 million of
retained earnings were restricted by this requirement as to payment of cash
dividends on common stock.
6. PREFERRED STOCK (Subject to Purchase or Sinking Funds):
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend. Retirements underSeries 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 are at par values.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 aggregate 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 through 2000 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1996 $2,439 1999 $2,440
1997 2,440 2000 2,440
1998 2,440
The changes in "Total Preferred Stock (Subject to Purchase or Sinking
Funds)" during 1995, 1994 and 1993 are summarized as follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1992 940,529 $ 58,639
Shares Redeemed:
$100 par value (7,374) (737)
$50 par value (51,187) (2,558)
Balance December 31, 1993 881,968 55,344
Shares Redeemed:
$100 par value (8,072) (807)
$50 par value (51,802) (2,591)
Balance December 31, 1994 822,094 51,946
Shares Redeemed:
$100 par value (6,809) (681)
$50 par value (51,666) (2,583)
Balance December 31, 1995 763,619 $ 48,682
7. INCOME TAXES:
Total income tax expense for 1995, 1994 and 1993 is as follows:
1995 1994 1993
(Thousands of Dollars)
Current taxes:
Federal $ 94,137 $66,597 $60,577
State 14,265 9,505 6,822
Total current taxes 108,402 76,102 67,399
Deferred taxes, net:
Federal (7,319) 7,727 12,197
State (603) 2,118 4,387
Total deferred taxes (7,922) 9,845 16,584
Investment tax credits:
Amortization of amounts
deferred (credit) (3,230) (3,231) (3,245)
Total income tax expense $ 97,250 $82,716 $80,738
47
The difference in actual income taxes and the income taxes
calculated from the application of the statutory Federal income
tax rate (35% for 1995, 1994 and 1993) to pretax income is
reconciled as follows:
1995 1994 1993
(Thousands of Dollars)
Net income $169,185 $152,043 $145,968
Total income tax expense:
Charged to operating expenses 96,956 84,066 81,280
Charged (credited) to other income 294 (1,350) (542)
Total pretax income $266,435 $234,759 $226,706
Income taxes on above at statutory
Federal income tax rate $ 93,252 $ 82,166 $ 79,347
Increases (decreases) attributable to:
Allowance for equity funds used
during construction (3,325) (2,796) (2,624)
Amortization of deferred
return on plant investment 1,486 1,486 1,486
Depreciation differences 3,268 2,994 2,531
Amortization of investment
tax credits (3,230) (3,231) (3,245)
State income taxes (less Federal
income tax effect) 8,880 7,555 7,286
Deferred income tax flowback at
higher than statutory rates (3,310) (3,647) (3,641)
Other differences, net 229 (1,811) (402)
Total income tax expense $ 97,250 $ 82,716 $ 80,738
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $468.9
million at December 31, 1995 and $485.8 million at December 31,
1994 determined in accordance with Statement No. 109 (see Note
1J) are
as follows:
1995 1994
(Thousands
1997 1996
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 48,512 $ 50,513
Cycle billing 19,143 17,521
Nuclear operations expenses 3,755 206
Deferred compensation 5,562 5,450
Other postretirement benefits 6,371 3,187
Other 2,929 3,627
Total deferred tax assets 86,272 80,504
Deferred tax liabilities:
Property plant and equipment 520,294 533,394
Pension expense 14,191 9,022
Reacquired debt 6,680 7,146
Research and experimentation 6,196 2,276
Other 7,801 14,458
Total deferred tax liabilities 555,162 566,296
Net deferred tax liability $468,890 $485,792
The Internal Revenue Service has examined and closed consolidated
Federal income tax returns of SCANA Corporation through 1989 and
is currently examining SCANA's 1990, 1991 and 1992 Federal income
tax returns. Adjustments are currently proposed by the examining
agent. SCANA does not anticipate that any adjustments which
might result from this examination will have a significant impact
on the earnings or financial position of the Company.
48
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the
Company's financial instruments at December 31, 1995 and 1994 are
as follows:
1995 1994
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
Cash and temporary cash
investments $ 6,798 $ 6,798 $ 346 $ 346
Investments 61 61 61 61
Liabilities:
Short-term borrowings 81 81 100,000 100,000
Notes payable - affiliated
companies - - 19,409 19,409
Long-term debt 1,315,412 1,412,213 1,264,233 1,195,023
Preferred stock (subject
to purchase or sinking funds) 48,682 46,603 51,946 49,348
The information presented herein is based on pertinent
information available to the Company as of December 31, 1995 and
1994. 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, 1995, 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. Settlement of long term debt may not be possible
or may not be a prudent management decision.$ 6.0 $ 6.0 $ 5.4 $ 5.4
Investments 5.3 5.3 0.6 0.6
Liabilities:
Short-term borrowings are valued at their carrying amount.
The fair value of preferred13.3 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) 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.
4912.5 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
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 and short-term
borrowings, excluding amounts classified as long-term (Notes 3
and 4), at December 31, 1995, 1994 and 1993 and for the years
then ended are as follows:
1995 1994 1993
(Millions of dollars)
Authorized lines of credit at year-end $165.0 $165.0 $212.0
Unused lines of credit at year-end $165.0 $165.0 $212.0
Short-term borrowings outstanding at
year-end:
Commercial paper $ 80.5 $100.0 $ 1.0
Weighted average interest rate 5.83% 6.04% 3.35%
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
The Company entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina.
Construction of the plant started in November 1992. Commercial
operation began in January 1996. The cost of the Cope plant,
excluding AFC, is $410.9 million. In addition, the transmission
lines for interconnection with the Company's system cost $22.5
million.
Under the Duke/Fluor Daniel contract the aggregate amount of
required minimum payments remaining at December 31, 1995 is $4.2
million due in 1996. Through December 31, 1995 the Company had
paid $378.7 million under the contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with the
Company's 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 $1.9 billion for any
losses at Summer Station. The Company pays annual premiums and,
in addition, could be assessed a retroactive premium not to
exceed 7 1/2 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 $8.2 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
financial position and results of operations.
50
C. Environmental
As described in Note 1M of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, estimates are made of the cost, if any, to investigate
and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual
expenditures could differ significantly from original estimates.
Amounts estimated and accrued 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 ten-year period for electric operations and an eight-year
period for gas operations. Such deferred amounts totaled $18.0
million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates to date include, among other items, the
costs estimated to be associated with the matters discussed in
the following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.
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
originally encompassed approximately eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority 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 (RI/FS) and a corresponding Scope
of Work. Field work began in November 1993. The Company is also
working with the City of Charleston to investigate potential
contamination from the manufactured gas plant which may have
migrated to the city's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to
be responsible for a $43.5 million increase in costs of the
aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes it has meritorious defenses against this claim and does
not expect its resolution to have a material impact on its
financial position or results of operations.
D. Claims and Litigation
The Company is engaged in various claims and litigation
incidental to its business operations which management
anticipates will be resolved without loss to the Company. No
estimate of the range of loss from these matters can currently be
determined.
51
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1995, 1994 and 1993 and
for the years then ended is as follows:
1995
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $1,006,566 $ 200,632 $ 3,889 $1,211,087
Operating expenses,
excluding depreciation
and amortization 657,452 169,768 10,429 837,649
Depreciation and
amortization 103,961 12,616 1,007 117,584
Total operating expenses 761,413 182,384 11,436 955,233
Operating income (loss) $ 245,153 $ 18,248 $ (7,547) 255,854
Add - Other income, net 9,553
Less - Interest charges 96,222
Net income $ 169,185
Capital expenditures:
Identifiable $ 245,016 $ 19,670 $ 265 $ 264,951
Utilized for overall Company operations 27,816
Total $ 292,767
Identifiable assets at
December 31, 1995:
Utility plant, net $2,850,647 $ 209,847 $ 1,878 $3,062,372
Inventories 76,697 2,155 561 79,413
Total $2,927,344 $ 212,002 $ 2,439 3,141,785
Other assets 660,648
Total assets $3,802,433
1994
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $975,526 $201,746 $ 4,002 $1,181,274
Operating expenses,
excluding depreciation
and amortization 659,610 173,717 10,577 843,904
Depreciation and
amortization 95,666 11,060 226 106,952
Total operating expenses 755,276 184,777 10,803 950,856
Operating income (loss) $ 220,250 $ 16,969 $ (6,801) 230,418
Add - Other income, net 7,271
Less - Interest charges 85,646
Net income $ 152,043
Capital expenditures:
Identifiable $ 359,510 $ 40,923 $ 347 $ 400,780
Utilized for overall Company operations 20,167
Total $ 420,947
Identifiable assets at
December 31, 1994:
Utility plant, net $2,717,147 $201,018 $ 1,791 $2,919,956
Inventories 85,113 2,605 495 88,213
Total $2,802,260 $203,623 $ 2,286 3,008,169
Other assets 578,922
Total assets $3,587,091
52
1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,547 $174,035 $ 3,851 $1,118,433
Operating expenses,
excluding depreciation
and amortization 639,808 148,349 9,737 797,894
Depreciation and
amortization 91,142 9,903 175 101,220
Total operating expenses 730,950 158,252 9,912 899,114
Operating income (loss) $ 209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585
Less - Interest charges 79,936
Net income $ 145,968
Capital expenditures:
Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934
Total $ 300,620
Identifiable assets at
December 31, 1993:
Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603
Inventories 66,181 2,526 463 69,170
Total $2,511,647 $180,990 $2,136 2,694,773
Other assets 495,166
Total assets $3,189,939
53
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1995
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $308,759 $275,139 $339,937 $287,252 $1,211,087
Operating income 67,189 53,153 87,023 48,489 255,854
Net Income 45,249 30,870 65,040 28,026 169,185
1994
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $313,321 $263,033 $327,066 $277,854 $1,181,274
Operating income 63,520 43,316 79,133 44,449 230,418
Net Income 45,340 24,348 57,619 24,736 152,043
54
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 27, 1995 to hold office
until the next annual meeting of the Company's stockholders on April 25, 1996.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 52 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.
William B. Bookhart, Jr. 54 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 66 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC;
South Carolina National Corporation,
Columbia, SC; Wachovia Bank of South
Carolina, N.A., Columbia, SC.
Hugh M. Chapman 63 Since January 1, 1992, Chairman of
(1988) NationsBank South, Atlanta, GA (a division
of NationsBank Corporation, bank holding
company).
From September 1, 1990 to December 31, 1991,
Vice Chairman and Director, C&S/Sovran
Corporation, Atlanta, GA.
Prior to September 1, 1990, President and
Director, Citizens & Southern
Corporation, Atlanta, GA and Chairman
of the Board, Citizens & Southern
South Carolina Corporation, Columbia,
SC.
Director, SCANA Corporation, Columbia, SC.
55
Name and Year First
Became Director Age Principal Occupation; Directorships
James B. Edwards, D.M.D. 68 For more than five years, President and
(1986) Professor of Maxillofacial Surgery,
Medical University of South Carolina,
Charleston, SC.
U.S. Secretary of Energy from January
1981 to November 1982.
Governor of South Carolina, 1975-1979.
Director, Phillips Petroleum Co.,
Bartlesville, OK; WMX Technologies, Inc.,
Oak Brook, IL; General Engineering
Laboratories, Inc., Charleston SC;
GS Industries, Inc., Charlotte, NC; IMO
Industries, Inc., Lawrenceville, NJ;
National Data Corporation, Atlanta, GA;
SCANA Corporation, Columbia, SC.
Elaine T. Freeman 60 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. 64 For more than five years, Chairman of the
(1987) 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; InterCel, Inc., West Point, GA;
The Liberty Corporation, Greenville, SC;
SCANA Corporation, Columbia, SC.
Benjamin A. Hagood 68 Since January 1, 1993, Chairman of the
(1974) Board William M. Bird and Company, Inc.,
Inc., Charleston, SC (wholesale
distributor of floor covering material).
For more than two years prior to January 1,
1993, President and Director, William M.
Bird and Company, Inc., Charleston, SC.
Director, SCANA Corporation, Columbia, SC.
56
Name and Year First
Became Director Age Principal Occupation; Directorships
W. Hayne Hipp 56 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.
Bruce D. Kenyon 53 For more than five years, President and
(1991) Chief Operating Officer of the Company.
Director, SCANA Corporation, Columbia, SC.
F. Creighton McMaster 66 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor
of petroleum products).
Director, First Union National Bank of
South Carolina, Greenville, SC; SCANA
Corporation, Columbia, SC.
Henry Ponder, Ph.D. 67 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Suntrust Banks, Inc., Nashville,
TN; SCANA Corporation, Columbia, SC.
John B. Rhodes 65 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.
William B. Timmerman 49 Since December 13, 1995, President of SCANA
(1991) 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
SCANA Corporation.
For more than five years prior to February
20, 1996, Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC;
InterCel, Inc., West Point, GA.
57
Name and Year First
Became Director Age Principal Occupation; Directorships
E. Craig Wall, Jr. 58 For more than five years, President and
(1982) Director, Canal Industries, Conway, SC
(forest products industry).
Director, Sonoco Products Company,
Hartsville, SC; Ruddick Corporation,
Charlotte, NC; Nationsbank Corp.,
Charlotte, NC; Blue Cross/Blue Shield of
South Carolina, Columbia, SC; SCANA
Corporation, Columbia, SC.
58
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
L.M. Gressette, Jr. (1) 64W.B. Timmerman 51 Chairman of the Board and
Chief Executive Officer *-present
President - SCANA *-1995
B.D. Kenyon (1) 53 President and1997-present
Chief Operating Officer
1990-present
W.B. Timmerman (1) 49of SCANA 1996-1997
President -of SCANA 1995-present
President of MPX,SCANA
Communications, Inc.,
an affiliate 1996-present1996-1997
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. 4749 President of SCANA
Communications, Inc. 1997-present
Senior Vice President-
Retail Electric 1995-present
Senior Vice President-
Fossil & Hydro Production 1993-1994
Senior Vice President-
Production 1991-1992*-1994
W.A. Darby 5052 Senior Vice President -
Gas, SCANA Gas Group 1996-present
Vice President-Gas Operations *-present*-1996
President and Treasurer of
ServiceCare 1996-present
General Manager of ServiceCare,
Inc., an affiliate 1994-present
J. L. Skolds 45 Senior Vice President - 1994-present
Generation
Vice President - Nuclear
Operations 1990-19941994-1996
K. B. Marsh (1) 4042 Vice President - Finance,
Chief Financial Officer
and Controller - SCANA 1996-present
Vice President - Finance,
Treasurer and Secretary,
1992-1996SCANA *-1996
Vice President - Finance
and Treasurer 1991-1992
Vice President - Corporate
Planning 1991
Vice President and
Controller *-1991
B.T. Zeigler (1) 40 Vice President - SCANA 1996-present
General Counsel of SCE&G 1995-present
Associate General Counsel -
SCE&G Legal Department 1992-1995
Partner - Lewis, Babcock &
Hawkins Law Firm *-1992
*Indicates position held at least since March 1, 1991
(1) Also an executive officer of SCANA
591993
63
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
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 parent, SCANA
Corporation, and none of the directors and executive officers of the
Company own any of the other classes of equity securities of the
Company. The required forms indicate that no equity securities of the
Company are owned by the 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 directors,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 Company believes that during
1995Performance Share Plan described hereafter.
(5) All other compensation for all Section 16(a) filing requirementsnamed 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 executive
officers, directorssubsidiaries' retirement plans of
$378,681 and greater than 10% beneficial owners were
complied with except that one report covering initial ownershipCompany contributions to defined contribution plans of the
Company's preferred stock was filed late by Kevin B. Marsh and Belton
T. Zeigler.
ITEM 11. EXECUTIVE COMPENSATION$21,269.
64
The following table contains information with respect to
compensation paid or accrued duringshows the years 1995, 1994 and 1993 to
the Chief Executive Officer of the Company and to each of the other
four most highly compensated executive officers of the Company during
1995 who were serving as executive officers of the Company at the end
of 1995.
SUMMARY COMPENSATION TABLE
Name and Principal Year Annual Compensation Long-Term
Position Compensation
(1) (2)
Salary Bonus Other Payouts
($) ($) Annual
Compen-
sation
($) (3) (4)
LTIP All Other
Payouts Compensa-
($) tion ($)
L. M. Gressette, Jr. 1995 449,246(5) 197,500 65,779 390,156 26,955
Chairman of the 1994 416,609 0 2,255 173,375 24,996
Board and Chief 1993 383,557 186,615 61,699 266,007 23,013
Executive Officer
B. D. Kenyon 1995 318,542 104,353 7,107 172,240 19,113
President and Chief 1994 313,581 96,768 2,649 81,619 18,815
Operating Officer 1993 297,760 99,090 4,201 125,792 17,866
W. B. Timmerman 1995 254,214 101,588 987 150,353 15,127
Chief Financial 1994 235,099 19,725 1,323 70,751 14,106
Officer and 1993 220,752 95,738 2,828 109,768 13,245
Assistant Secretary
G. J. Bullwinkel 1995 189,097 70,904 487 90,402 11,346
Senior Vice President 1994 170,828 42,573 762 38,249 9,826
- - Retail Electric 1993 148,705 51,975 1,477 58,489 0
J. L. Skolds 1995 176,156 74,151 54 76,128 10,569
Senior Vice President 1994 156,731 42,573 2,146 38,249 9,404
- - Generation 1993 146,438 43,605 4,065 58,489 0
______________
(1) Paymentstarget awards made in 1997, for potential payment in
2000, under the annual Performance Incentive Plan described hereafter.
(2) Other annual compensation consists of (i) for Mr. Gressette, perquisites
including compensation related to whole life insurance premiums for 1995
in the amount of $54,642, (ii) for Mr. Kenyon, a lump sum payment in lieu
of a base salary increase in 1995 and (iii) for all named officers,
payments to cover taxes on benefits.
(3) Payments under the long-term Performance Share Plan described hereafter.
(4) All other compensation consists solely of Company contributions to defined
contribution plans based on the funding formula applicable to all
employees of the Company.
(5) Reflects actual salary paid in 1995. Base salary of $460,000, became
effective in May of 1995.
60
Long-Term Performance Share Plan
The long-term Performance Share Plan for officers of SCANA and its subsidiaries measures SCANA's Total Shareholder Return ("TSR")
relative to a group of peer companies over a three-year period. The
"PSP Peer Group" includes 94 electric and gas utilities, none of which
have annual revenues of less than $100 million.
TSR is stock price increase over the three-year period, plus cash
dividends paid during the period, divided by stock price as of the
beginning of the period. Comparing SCANA's TSR to the TSR of a large
group of other utilities reflects SCANA's recognition that investors
could have invested their funds in other utility companies and
measures how well SCANA did when compared to others operating in
similar interest, tax, economic and regulatory environments.
Executives eligible to participate in the Performance Share Plan
are assigned target award opportunities annually based primarily on
their salary level. In determining award sizes, levels of
responsibilities and competitive practices also are considered.
Awards under this plan represent a significant portion of executives
"at-risk" compensation. To provide additional incentive for
executives, and to ensure that executives are only rewarded when
shareholders gain, actual payouts may exceed the median of the market
when performance is above the 50th percentile of the peer group. For
lesser performance, awards will be at or below the market median.
Payouts occur when SCANA's TSR is in the top two-thirds of the
PSP Peer Group, and vary based on SCANA's ranking against the peer
group. Executives earn threshold payouts of 0.4 times target 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 at 1.5 times target when SCANA's 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 in
the bottom one-third of the peer group. Awards are denominated in
shares of SCANA Common Stock and may be paid in either stock or a
combination of stock and cash.
For the three-year period from 1993 through 1995, SCANA's TSR was
at the 98th percentile of the PSP Peer Group. This resulted in
payouts in February 1996 at 150% of target shares awarded paid in a
combination of stock and cash.
The following table shows the target awards made in 1995 for
potential payment in 1998 under the long-term Performance Share Plan,subsidiaries', and
estimated future payouts under that plan at threshold, target and maximum levels for the
named executive officers. Mr. Gressette's
award for the 1995-1997 performance period is prorated to reflect his
retirement in February 1997.
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1995 TO BE PAID IN 1998
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 #)
L. M. Gressette, Jr. 6,023 1995-1997 2,409 6,023 9,035
B. D. Kenyon 3,700 1995-1997 1,480 3,700 5,550
W. B. Timmerman 3,220 1995-1997 1,288 3,220 4,830
G. J. Bullwinkel 1,940 1995-1997 776 1,940 2,910
J. L. Skolds 1,940 1995-1997 776 1,940 2,910
61
DEFINED BENEFIT PLANS
In addition to the qualified Retirement Plan for all employees,
the Company has Supplemental Executive Retirement Plans ("SERP") for
certain eligible employees, including officers. 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.
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 42,311 56,415 70,519 84,623 87,476
200,000 57,311 76,415 95,519 114,623 118,726
250,000 72,311 96,415 120,519 144,623 149,976
300,000 87,311 116,415 145,519 174,623 181,226
350,000 102,311 136,415 170,519 204,623 212,476
400,000 117,311 156,415 195,519 234,623 243,726
450,000 132,311 176,415 220,519 264,623 274,976
500,000 147,311 196,415 245,519 294,623 306,226
550,000 162,311 216,415 270,519 324,623 337,476
600,000 177,311 236,415 295,519 354,623 368,726
The compensation shown in the column labeled "Salary" of the
Summary Compensation Table for the individuals named therein is
covered by the Retirement Plan and/or a SERP. As of December 31,
1995, Messrs. Gressette, Kenyon, Timmerman, Bullwinkel and Skolds had
credited service under the Retirement Plan (or its equivalent under
the SERP) of 33, 22, 17, 25 and 10 years, respectively. 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, 1996 and are not subject to any deduction for Social
Security or other offset amounts.
The Company also has a Key Employee Retention Program (the "Key
Employee Retention Program") covering officers and certain other
executive employees that provides supplemental retirement and/or death
benefits for participants. Under the program, each participant may
elect to receive either 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 an optional death benefit payable to a participant's
designated beneficiary monthly 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 above are participating in the program. Estimated annual
retirement benefits payable at age 65 based on projected eligible
compensation (assuming increases of 4% per year) to the five executive
officers named in the Summary Compensation Table are as follows:
Mr. Gressette - $113,790; Mr. Kenyon - $122,658; Mr. Timmerman -
$129,942; Mr. Bullwinkel - $90,887; and Mr. Skolds - $93,234.
62
TERMINATION, SEVERANCE AND CHANGE OF CONTROL ARRANGEMENTS
The Company has a Key Executive Severance Benefit Plan (the
"Severance Plan") intended to assure the objective judgment of, and to
retain the loyalties of, key executives when the Company is faced with
a potential change in control or a change in control by providing a
continuation of salary and benefits after a participant's employment
is terminated by the Company during a potential change in control,
after a change in control without just cause, disability, retirement
or death or by the participant for good reason after a change in
control. All of the executive officers named in the Summary
Compensation Table except Mr. Gressette have been designated as
participants in the Severance Plan.
When a potential change in control occurs, a participant is obli-
gated to remain with the Company for six months unless his employment
is terminated for disability or normal retirement or until a change in
control occurs. Upon a change in control resulting in an officer's
termination, the Severance Plan provides for guaranteed severance
payments equal to three times the annual compensation of the officer
plus payments under certain of the Company's incentive and retirement
plans. The officer also would receive an additional amount (a "gross-
up" payment) for any IRC Section 4999 excess tax or any such other
similar tax applicable to the severance payments. In addition, for 36
months after termination, the officer would receive coverage for
medical benefits and life insurance so as to provide the same level of
benefits previously enjoyed under group plans or individual policy
contracts or otherwise as determined by the Executive Committee of the
Board of Directors. Such benefits however would be reduced to the
extent that the participant receives similar benefits during the
period from another employer.
In addition to the Severance Plan, in the event of a merger,
consolidation or acquisition in which SCANA is not the surviving
corporation, target awards under the Performance Share Plan will
become immediately payable based on SCANA's shareholder return
performance as of the end of the most recently completed calendar year
for each performance period as to which the grant of target shares has
occurred at least six months previously.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1995, no officer, employee or former officer of the
Company or its affiliates served as a member of the Long-Term
Compensation Committee or the Performance Committee, except Mr.
Gressette who served as a member of the Performance Committee.
Although Mr. Gressette was an ex-officio, nonvoting member of the
Performance Committee during 1995, he did not participate in any of
its deliberations concerning executive officer compensation.
Since January 1, 1995, the Company has engaged in business
transactions with entities with which 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 executive officers.
Mr. Chapman is Chairman of NationsBank South, a division of
NationsBank Corporation. Since January 1, 1995, the Company has
engaged in various transactions in which affiliates of NationsBank
Corporation acted as lender or provider of lines of credit or credit
support to the Company and its affiliates. The amount paid during
1995 by the Company and its affiliates to NationsBank Corporation
affiliates on account of such transactions was $3,339,270. It is
anticipated that transactions such as described above will continue in
the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum
Company. Purchases from Winnsboro Petroleum Company totaling $71,413
for fuel oil and gasoline were made during 1995 by the Company and its
affiliates. It is anticipated that such purchases will continue in
the future.
During 1995, there existed one executive officer-director
interlock where an executive officer of SCANA Corporation served as a
director of another company that had an executive officer serving on
one of the SCANA Board of Directors' committees which deals with
compensation matters. Mr. Gressette, Chairman of the Board and Chief
Executive Officer of the Company, served as a director of The Liberty
Corporation and Mr. Hipp, President and Chief Executive Officer of The
Liberty Corporation, served as a member of the Company's Long-Term
Compensation Committee.
63
Compensation of Directors
Fees. During 1995, directors who were not employees of the
Company were paid $16,000 annually for services rendered, plus $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.
Directors who are employees of the Company or its affiliates receive
no compensation for serving as directors or attending meetings.
Deferral Plan. SCANA has a plan pursuant to which directors may
defer all or a portion of their fees for services rendered and meeting
attendance. Interest is earned on the deferred amounts at a rate set
by the Performance Committee. During 1995 and currently, the rate is
set at the announced prime rate of Wachovia Bank of South Carolina.
Mr. Cassels and Mr. Rhodes were the only directors participating in
the plan during 1995. Mr. Cassels became a participant in January
1994 and Mr. Rhodes in July 1987, and interest credited to their
deferral accounts during 1995 was $3,591.94 and $19,557.86,
respectively.
Endowment Plan. Each director participates in the Directors'
Endowment Plan, which provides that SCANA make a tax deductible,
charitable contribution totaling $500,000 to institutions of higher
education nominated by the director. A portion is contributed upon
retirement of the director and the remainder upon the director's
death. The plan is funded in part through insurance on the lives of
the directors. Designated in-state institutions of higher education
must be approved by the Chief Executive Officer of SCANA; any out-of-
state designation must be approved by the Performance Committee. The
designated institutions are reviewed on an annual basis by the Chief
Executive Officer to assure compliance with the intent of the program.
The plan is intended to reinforce SCANA's commitment to quality higher
education and is intended to enhance SCANA's ability to attract and
retain qualified board members.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
All shares of the Company's Common Stock are held, beneficially
and of record, by SCANA Corporation.
The table set forth below indicates the shares of SCANA's Common
Stock beneficially owned as of March 8, 1996 by each director and
nominee, each of the executive officers named in the Summary Compensation Table on page 59, and the directors and executive
officerspreceding page.
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1997 TO BE PAID IN 2000
Number of the Company as a group.
SECURITY OWNERSHIP OF MANAGEMENTPerformance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation
Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature
Owner of Ownership 1 Owner of Ownership 1
B. L. Amick 2,486 W. Hayne Hipp 2,800Rights (#) or Payout
Threshold Target Maximum
($ or #) ($ or #) ($ or #)
W. B. Bookhart, Jr. 15,761 B. D. Kenyon 18,883Timmerman 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 17,255 F. C. McMaster 5,6303,010 1997-1999 1,204 3,010 4,515
K. B. Marsh 3,010 1997-1999 1,204 3,010 4,515
W. T. Cassels, Jr. 2,000 Henry Ponder 12,381
H. M. Chapman 6,000 J. B. Rhodes 7,780
J. B. Edwards 4,665 J. L. Skolds 6,414
E. T. Freeman 4,220 W. B. Timmerman 36,459A. Darby 2,040 1997-1999 820 2,040 3,060
L. M. Gressette, Jr. 47,493 E. C. Wall, Jr. 14,000
B. A. Hagood 2,370
All directors and executive officers as a group (21 persons) TOTAL 247,243
TOTAL PERCENT OF CLASS 0.2%
The information set forth above as to the security ownership has
been furnished to the Company by such persons.
_____________________
1 Includes shares owned by close relatives, the beneficial
ownership
of which is disclaimed by the director or nominee, as follows:
Mr. Amick - 480; Mr. Bookhart - 4,498; Mr. Gressette - 1,060;
Mr. Hagood - 334; Mr. McMaster - 2,000.
Includes shares purchased through December 31, 1995, but not
thereafter, by the Trustee under the Savings Plan.
64
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 30.
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
65
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/Bruce D. Kenyon
(NAME AND TITLE) Bruce D. Kenyon, President and Chief
Operating Officer
DATE February 20, 1996
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/L. M. Gressette, Jr.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board,
Chief Executive Officer and Director
DATE February 20, 1996
(ii) Principal financial officer:
BY (SIGNATURE) s/K. B. Marsh
(NAME AND TITLE) K. B. Marsh, Chief Financial Officer
DATE February 20, 1996
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and Controller
DATE February 20, 1996
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 20, 1996
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 20, 1996
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 20, 1996
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 20, 1996
66
BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 20, 1996
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 20, 1996
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 20, 1996
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Director
DATE February 20, 1996
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 20, 1996
BY (SIGNATURE) s/E. C. Wall, Jr.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 20, 1996
67
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
(Filed herewith)......................................... 71
I. Articles of Amendment dated December 13, 1995
(Filed herewith)......................................... 72
J. Copy of By-Laws of the Company as revised and
amended thru December 15, 1993 (Exhibit 3-AZ to
Form 10-K for the year ended December 31, 1993,
File No. 1-3375)......................................... #
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)...... #
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
# Incorporated herein by reference as indicated.
68
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
4. (continued)
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)......................... #
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)......................... #
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)............................................ #
11. Statement Re Computation of Per Share Earnings
Not Applicable
# Incorporated herein by reference as indicated.
69
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
12. Statement re Computation of Ratios (Filed herewith)........ 74
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.......................... 78282 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. Power of Attorney
Not Applicable
27. Financial Data Schedule
Filed herewith
28. Information from Reports furnished to State
Insurance Regulatory Authorities
Not Applicable
99. Additional Exhibits
Not Applicable
# Incorporated herein by reference as indicated.
70