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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, 1993
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 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
Securities registered pursuant to 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 Stock 8.72% Cumulative Preferred Stock
par value $50 per share par value $50 per share
8.12% Cumulative Preferred Stock 7.70% Cumulative Preferred Stock
par value $100 per share par value $100 per share
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 .
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 stock held by
nonaffiliates of the registrant. The aggregate market value shall be
computed by reference to the price at which the stock was sold, or the
average bid and asked prices of such stock, 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 stock held by
nonaffiliates of the registrant as of February 28, 1994 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 28, 1994 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 .......................................... 18
Item 3. Legal Proceedings ................................... 20
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 20
PART II
Item 5. Market for Registrant's Common Stock
and Related Security Holder Matters ................ 20
Item 6. Selected Financial Data ............................. 21
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations....... 22
Item 8. Financial Statements and Supplementary Data ......... 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 60
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 60
Item 11. Executive Compensation .............................. 66
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 73
Item 13. Certain Relationships and Related Transactions ...... 73
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 74
SIGNATURES ........................................................ 75
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
Affiliate................... Wholly-owned subsidiary of SCANA Corporation
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................... 1 million BTUs
DHEC........................ South Carolina Department of Health and
Environmental Control
DOE......................... United States Department of Energy
EPA......................... United States Environmental Protection Agency
FERC........................ United States Federal Energy Regulatory
Commission
Fuel Company................ South Carolina Fuel Company, Inc., an
affiliate
GENCO....................... South Carolina Generating Company, Inc., an
affiliate
KVA......................... Kilovolt-ampere
KW.......................... Kilowatt
KWH......................... Kilowatt-hour
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
PSA......................... The South Carolina Public Service Authority
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935
SCANA....................... SCANA Corporation and subsidiaries
Southern Natural............ Southern Natural Gas Company
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipe Line Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams coal-fired, electric
generating station owned by GENCO
4
PART I
ITEM 1. BUSINESS
THE COMPANY
Organization
The Company, a wholly owned subsidiary of SCANA, is a South
Carolina corporation organized in 1924 and has its principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Company had 4,166
full-time, permanent employees as of December 31, 1993 as
compared to 4,168 full-time, permanent employees as of December
31, 1992.
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 and Service Area
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 areas of Columbia and Charleston, South
Carolina. The Company's business is seasonal in that, 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 29 of the 46 counties
in South Carolina and covers more than 19,000 square miles.
Total estimated population of the counties representing the
Company's combined service area is approximately 2.3 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, 1993, 1992 and 1991 is contained in Note 11 of
Notes to Consolidated Financial Statements and all such
information is incorporated herein by reference.
5
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The cash requirements of the Company arise primarily from
its operational needs and its construction program. During 1994
the Company is expected to meet its capital requirements
principally through internally generated funds (approximately 32%
excluding dividends), the issuance and sale of debt securities
and additional equity contributions from SCANA. Short-term
liquidity is expected to be provided by issuance of commercial
paper. The timing and amount of such sales and the type of
securities to be sold will depend upon market conditions and
other factors.
The Company recovers the costs of providing services through
rates charged to customers. Rates for regulated services are
based on historical costs. As inflation occurs and the Company
expands its construction program it is necessary to seek
increases in rates, and on June 7, 1993 the PSC issued an order
granting the Company a 7.4% annual increase, based on a test
year, in retail electric rates to be implemented in two phases of
$42.0 million annually effective June 1993 and $18.5 million
annually effective June 1994. The Company's future financial
position and results of operations will be affected by its
ability to obtain adequate and timely rate relief. (See
"Regulation.")
The Company's estimates of its cash requirements for
construction and nuclear fuel expenditures, which are subject to
continuing review and adjustment, for 1994 and the four-year
period 1995-1998 as now scheduled are as follows:
Type of Facilities 1994 1995-1998
(Thousands of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $245,039 $ 539,180
Transmission. . . . . . . . . . . . . . . 21,230 94,177
Distribution. . . . . . . . . . . . . . . 58,178 295,523
Other . . . . . . . . . . . . . . . . . . 12,815 42,975
Nuclear Fuel. . . . . . . . . . . . . . . . 28,064 84,770
Gas . . . . . . . . . . . . . . . . . . . . 15,814 62,276
Transit . . . . . . . . . . . . . . . . . . 422 749
Common. . . . . . . . . . . . . . . . . . . 30,650 54,715
Nonutility . . . . . . . . . . . . . . . . 139 545
Total . . . . . . . . . . . . . . $412,351 $1,174,910
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program
for the periods 1994 and 1995-1998 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 in Orangeburg
County. Construction of the plant began in November 1992 with
commercial operation expected in late 1995 or early 1996. The
estimated price of the Cope plant, excluding financing costs
and AFC but including an allowance for escalation, is $450
million. In addition, the transmission lines for interconnection
with the Company's system are expected to cost $26 million.
The steam generators at Summer Station will be replaced
during the 1994 regularly scheduled refueling outage. In January
1994 the Company, acting on behalf of itself and the PSA (as co-
owners of the 885 Megawatt Summer Station), reached a settlement
with Westinghouse Electric Corporation (Westinghouse) resolving a
dispute involving steam generators provided by Westinghouse to
Summer Station which are defective in design, workmanship and
materials. Terms of the settlement are confidential by agreement
of the parties and order of the court. The Company had filed an
action in May 1990 against Westinghouse in the U. S. District
Court for South Carolina; an order dismissing this suit was
issued on January 12, 1994.
6
During 1993 the Company expended approximately $20 million
as part of a program to extend the operating lives of certain
generating facilities. Additional improvements under the program
to be made during 1994 are estimated to cost approximately $17
million.
Financing Program
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 12
consecutive months out of the 15 months prior to the month of
issuance is at least twice the annual interest requirements on
all Class A Bonds to be outstanding (Bond Ratio). For the year
ended December 31, 1993 the Bond Ratio was 3.70. The issuance of
additional Class A Bonds is restricted also to an additional
principal amount equal to 60% of unfunded net property additions
(which unfunded net property additions totaled approximately
$219.9 million at December 31, 1993), Class A Bonds issued on the
basis of retirements of Class A Bonds (which retirement credits
totaled $10.9 million at December 31, 1993), and Class A Bonds
issued on the basis of cash on deposit with the Trustee.
The Company has placed a new bond indenture (New Mortgage)
dated April 1, 1993 on substantially all of its electric
properties under which its future mortgage-backed debt (New
Bonds) will be issued. New Bonds are expected to be 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 $157 million were
available for such purpose as of December 31, 1993), 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 12 consecutive months out of the 18 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, 1993 the New Bond
Ratio was 5.0.
On April 29, 1993 the Securities and Exchange Commission
declared effective a registration statement for the issuance of
up to $700 million of New Bonds. The following series,
aggregating $600 million, have been issued under such
registration statement:
On June 9, 1993, $100 million, 7 5/8% Series due
June 1, 2023 to repay short-term borrowings in a like
amount.
On July 1, 1993, $100 million, 6% Series due
June 15, 2000, and $150 million, 7 1/8% Series due
June 15, 2013, and on July 20, 1993, $150 million,
7 1/2% Series due June 15, 2023, to redeem, on
July 20, 1993, $382,035,000 of First and Refunding
Mortgage Bonds maturing between 1999 and 2017 and
bearing interest at rates between 8% and 9 7/8% per
annum.
On December 20, 1993. $100 million, 6 1/4% Series due
December 15, 2003 to repay short-term borrowings in a
like amount.
On June 1, 1993 the Company redeemed the following
amounts of First and Refunding Mortgage Bonds:
$35 million, 10 1/8% Series due 2009 and $13 million,
9 7/8% Series due 2009.
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 FERC authority to issue short-term indebted-
ness. The FERC has authorized the Company to issue up to $200
million of unsecured promissory notes or commercial paper with
maturity dates of 12 months or less but not later than December
31, 1995.
7
The Company has $127.0 million authorized and unused
lines of credit at December 31, 1993.
SCE&G'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 12 consecutive months immediately preceding the month of
issuance is 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, 1993
the Preferred Stock Ratio was 2.52.
The ratio of earnings to fixed charges (SEC Method) was
3.57, 2.73, 3.32, 3.33 and 3.04 for the years ended December 31,
1993, 1992, 1991, 1990 and 1989, respectively.
Additional Capital Requirements
In addition to the Company's capital requirements for 1994
described above, approximately $5.0 million will be required for
refunding and retiring outstanding securities and obligations.
For the years 1995-1998, the Company has an aggregate of $149.4
million of long-term debt maturing (including approximately $43.9
million for sinking fund requirements, of which $43.5 million may
be satisfied by deposit and cancellation of bonds issued upon the
basis of property additions or bond retirement credits) and $9.9
million of purchase or sinking fund requirements for preferred
stock.
Actual 1994 expenditures may vary from the estimates set
forth above due to factors such as inflation, economic
conditions, regulation, legislation, rates of load growth,
environmental protection standards and the cost and availability
of capital.
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 fuel. To finance
nuclear and fossil fuel inventories, Fuel Company issues, from
time to time, its promissory notes with maturities of less than
270 days ("Commercial Paper"). The issuance of Commercial Paper
is supported by an irrevocable revolving credit agreement which
expires July 31, 1996 and is guaranteed by the Company.
Accordingly, the amounts outstanding have been included in long-
term debt. The credit agreement provides for a maximum amount of
$75 million that may be outstanding at any time.
At December 31, 1993 Commercial Paper outstanding for
nuclear and fossil fuel inventories was approximately $36.8
million at a weighted average interest rate of 3.47%. Such
fuel inventories and fuel-related assets and liabilities are
included in the Company's financial statements. (See Notes 1 and
4 of Notes to Consolidated Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 1993 residential sales of electricity accounted for 43%
of electric sales revenues; commercial sales 29%; industrial
sales 21%; sales for resale 4%; and all other 3%. KWH sales by
classification for the years ended December 31, 1993 and 1992 are
presented below:
Sales
KWH %
Classification 1993 1992 Change
(thousands)
Residential 5,650,759 5,155,886 9.50
Commercial 4,844,422 4,538,862 6.73
Industrial 4,887,250 4,684,072 4.34
Sale for resale 1,005,968 946,357 6.30
Other 500,937 476,064 5.22
Total Territorial 16,889,336 15,801,241 6.89
Interchange 198,059 77,046 157.07
Total 17,087,395 15,878,287 7.61
8
The Company furnishes electricity for resale to three
municipalities, three investor-owned utilities, two electric
cooperatives and one public power authority. Such sales for
resale accounted for 4% of total electric sales revenues in 1993.
An addition of 6,973 electric customers to 468,901 total
customers contributed to an all-time peak demand record of 3,557
on July 29, 1993. The previous years' record of 3,380 MW was set
July 13, 1992.
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.
The Company's transmission system is part of the
interconnected grid extending over a large part of the southern
and eastern portion of the nation. The Company, Virginia Power
Company, Duke Power Company, Carolina Power & Light Company,
Yadkin, Incorporated and PSA are members of the Virginia-
Carolinas Reliability Group, one of the several geographic
divisions within the Southeastern Electric Reliability Council
which 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 1991-1993.
1991 1992 1993
Nuclear:
Per million BTU $ .57 $ .52 $ .47
Coal:
Company:
Per ton $41.61 $40.00 $39.95
Per million BTU 1.63 1.56 1.55
GENCO:
Per ton $42.12 $41.82 $41.64
Per million BTU 1.64 1.63 1.62
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.38 $ 1.27 $ 1.33
The fuel costs shown above exclude the effects of a PSC
approved offsetting of fuel costs through the application of
credits carried on the Company's books as a result of a 1980
settlement of certain litigation.
Fuel Supply
The following table shows the sources and approximate
percentages of total KWH generation (including Williams Station)
by each category of fuel for the years 1991-1993 and the
estimates for 1994 and 1995.
Percent of Total KWH Generated
Actual Estimated
1991 1992 1993 1994 1995
Coal 68% 65% 72% 77% 69%
Nuclear 21 29 22 17 26
Hydro 5 5 5 5 5
Natural Gas & Oil 6 1 1 1 -
100% 100% 100% 100% 100%
Coal is currently used at all four of the Company's major
fossil fuel-fired plants and GENCO's Williams Station. Unit
train deliveries are used at all of these plants. On December
31, 1993 the Company had approximately a 73-day supply of coal in
inventory and GENCO had approximately a 56-day supply.
9
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 the following percentages of estimated
requirements for 1994 (approximately 5.3 million tons, including
requirements of Williams Station) and expire at the dates
indicated (giving effect to the Company's potential to exercise
renewal options):
Range of % of Final
No. of Tons % of 1994 Sulfur Content Expiration Renegotiation
Per Year Requirement per Contract Date (1) Date (1)
966,664 18.2 up to 1.55 02/28/2001 02/28/1995
360,000 6.8 1.00 - 1.80 12/31/2002 12/31/1996
134,000 2.5 1.10 - 2.00 03/31/1996 03/31/1994
120,000 2.3 1.10 - 1.60 04/30/1996 04/30/1994
972,000 18.3 up to 1.50 12/31/2002 12/31/1996
192,832 3.6 0.80 - 1.50 06/30/2000 06/30/1994
2,745,496 51.7
(1) Contract extensions beyond the stated renegotiation date to
the final expiration date are subject to mutual agreement on
price, terms, quantity and quality.
All of the above contracts, except the contracts expiring in
March 1994 and April 1994 which have firm prices, are subject to
periodic price adjustments based on changes in indices published
by the U. S. Department of Labor.
Coal purchased in December 1993 had an average sulfur
content of 1.17%, which permitted the Company to comply with
existing environmental regulations. 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 DHEC that any more
stringent sulfur content requirements for existing plants are
contemplated. However, the Company will be required to meet the
more stringent emissions standards established by the Clean Air
Act (see "Environmental Control Matters").
The Company currently has adequate supplies of uranium under
contract to manufacture nuclear fuel for Summer Station through
1996. The following table summarizes all contract commitments
for the stages of nuclear fuel assemblies:
Commitment Contractor Regions(1) Term
Uranium NUEXCO Trading
Corporation 11 1994
Uranium Energy Resources
of Australia 9-13 1990-1996
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995
Enrichment DOE (2) Through 2022
Fabrication Westinghouse 1-21 1982-2009
Reprocessing None
(1) A region represents approximately one-third to one-half of
the nuclear core in the reactor at any one time. Region
no. 10 was loaded in 1993 and region no. 11 will be loaded
in 1994.
(2) The contract with the DOE is a "requirements" type
contract whereby the DOE supplies total enrichment
requirements for the unit through the year 2022, as
specified by its then current schedule.
The Company has on-site spent fuel storage capability until
at least 2008 and expects to be able to expand its storage
capacity over the life of Summer Station 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 Control Matters" for information regarding the
contract with the DOE for disposal of spent fuel.)
10
GAS OPERATIONS
Gas Sales
In 1993 residential sales accounted for 36% of gas sales
revenues; commercial sales 26%; industrial sales 17% and
transportation gas 21%. Dekatherm sales by classification for
the years ended December 31, 1993 and 1992 are presented below:
SALES
DEKATHERMS %
CLASSIFICATION 1993 1992 CHANGE
Residential 12,009,444 11,286,088 6.4
Commercial 8,842,728 9,029,256 (2.1)
Industrial 5,881,309 5,334,117 10.3
Transportation gas 6,993,817 5,906,697 18.4
Total 33,727,298 31,556,158 6.9
During 1993 the Company added 2,696 customers, increasing
its total customers to 221,278.
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 alternative fuels and
other factors.
The deregulation of natural gas prices at the wellhead which
took place on January 1, 1985 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 April 8, 1992, the FERC promulgated its Order No. 636,
which is 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 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, which,
while operating wholly within the state of South Carolina, is
served by two interstate pipelines.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for alternate fuel vehicles for federal, state,
municipal and private fleets which increase over a period of
years. The Company expects these requirements for alternate fuel
vehicles to develop business opportunities for the sale of
compressed natural gas as fuel for vehicles, but it cannot
predict the extent of this new market.
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts
with producers, brokers and interstate pipelines. The gas is
brought to South Carolina through contracts with both Southern
Natural and Transco. The volume of gas which Pipeline
Corporation is entitled to transport through these contracts on a
firm basis is shown below:
Maximum Daily
Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 160,000
Transco Firm Transportation 29,900
Total 189,900
11
Under a contract with Pipeline Corporation, the Company's
maximum daily contract demand is 184,000 MCF. 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 $3.81 in 1993 compared to
$3.65 in 1992.
To meet the requirements of the Company and its high
priority natural gas customers during periods of maximum demand,
Pipeline Corporation supplements its supplies of natural gas from
two LNG plants. The LNG storage tanks are capable of storing the
liquefied equivalent of 1,900,000 MCF of natural gas, of which
approximately 1,450,000 MCF were in storage at December 31, 1993.
On peak days the LNG plants can regasify up to 150,000 MCF per
day. Additionally, Pipeline Corporation had contracted for
6,398,035 MCF of natural gas storage space on December 31, 1993,
of which 4,880,484 MCF were in storage at such date. Propane
air peak shaving facilities located in the Company's
service area can supply an additional 137,400 MCF per day.
The Company believes that Pipeline Corporation's current
supplies under contract and spot market purchase of natural gas
are adequate to meet existing customer demands for service and to
accommodate growth.
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 regulatory
jurisdiction 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.
National Energy Policy Act of 1992
Congress has passed NEPA, the principal thrust of which is
to create a more competitive wholesale power supply market by
creating "exempt wholesale generators" (EWGs) designated by the
FERC, which are independent power producers (IPPs) whose owners
will not become holding companies under PUHCA. Upon application
of a wholesaler of electric energy, the FERC may order an
electric utility that owns transmission facilities used for
wholesale sales of electric energy to provide transmission
service (including any enlargement of transmission capacity
needed to provide the service) to the applicant. Charges for
transmission service must be "just and reasonable" and a utility
is entitled to recover "all legitimate, verifiable economic
costs" incurred in connection with any transmission service so
ordered. The FERC may not order such service where it (1) would
"unreasonably impair the continued reliability of electric
wheeling" judged by reference to "consistently applied regional
or national reliability standards, guidelines or criteria;" (2)
would result in "retail wheeling;" or (3) would conflict with
state laws governing retail marketing areas of electric
utilities. Electric utilities, including exempt and non-exempt
holding companies, may own and operate EWGs subject to advance
approval by state utility commissions, which are given access to
books and records of the EWG and its affiliates to the extent
that such a commission requires access to perform its
regulatory duties. It allows both registered and exempt
12
utility holding companies to acquire interests in foreign utility
companies engaged in the generation, transmission or distribution
of electricity or the retail distribution of gas, where a state
commission has certified that it has the ability to protect the
utility's retail ratepayers against adverse investments in
foreign utilities by affiliates of public utilities that such
commissions regulate. State Commissions must consider rate
making changes and other regulatory reform to ensure that
electric utilities' investments in energy efficiency and demand
side management programs are at least as profitable as investing
in new generating capacity. FERC has issued a Notice of Proposed
Rule Making to develop regulations under NEPA concerning EWGs and
electric transmission service.
NEPA also has provisions concerning nuclear power, alternate
fuel vehicles, minimum efficiency standards, integrated resource
planning, demand side management incentives, a variety of energy
research projects relating to environmental measures, electric
and magnetic fields, hydroelectric projects, and global warming.
It authorizes one step licensing for nuclear power plants and
requires EPA to issue standards for the Yucca Mountain repository
site for nuclear waste (see "Nuclear Fuel Disposal" under
"Environmental Control Matters"). To reduce dependence on
imported oil, NEPA imposes purchase requirements for alternate
fuel vehicles for federal, state, municipal and private fleets
which increase over a period of years (see "Gas Operations").
In the opinion of the Company, it will be able to meet
successfully the challenges of an altered business climate for
electric and gas utilities and natural gas businesses. Neither
the application of NEPA or FERC Order No. 636 nor the development
of an EWG industry, new markets and obligations for transmission
services for wholesale sales of electricity, nor deregulated
interstate natural gas markets is expected to have a material
adverse impact on the results of its operations, its financial
position or its business prospects.
Federal Energy Regulatory Commission
Pursuant to Section 204 of the Federal Power Act, the
Company must obtain FERC authority to issue short-term
indebtedness. The FERC has authorized the Company to issue up to
$200 million of unsecured promissory notes or commercial paper
with maturity dates of 12 months or less but not later than
December 31, 1995.
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: Neal Shoals (5,000 KW capability) and
Stevens Creek (9,000 KW capability) 1993; Columbia (10,000 KW
capability) 2000; Saluda Project (206,000 KW capability) 2007;
and Parr Shoals (14,000 KW capability) and Fairfield Pumped
Storage Project (512,000 KW capability) 2020. Pursuant to the
provisions of the Federal Power Act as amended by the Electric
Consumers Protection Act of 1986, applications for new licenses
were filed on December 30, 1991. No competing applications were
filed. The Neal Shoals license application was accepted for
filing by the FERC on September 30, 1992 and the Stevens Creek
application was accepted September 15, 1993. FERC has issued
Notices of Authorization for Continued Project Operation for both
projects until FERC has acted on SCE&G's applications for new
licenses. FERC has announced its intentions to perform a
Multiple-project Environmental Assessment for Neal Shoals and a
Multiple-project Environmental Impact Statement for Stevens
Creek.
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 States takes over a project or
the FERC issues a license to another applicant, the original
licensee shall be paid its net investment in the project (not to
exceed fair value) plus severance damages.
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. The NRC conducts semiannual reviews
that identify plants that have demonstrated an excellent level of
safety performance. Summer Station was recognized in both 1993
reviews as one of the top nuclear plants in the country.
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.
13
RATE MATTERS
The following table presents a summary of significant rate activity for
the years 1990-1993 based on test years:
REQUESTED GRANTED
Date of
General Rate Application/ Amount % Increase Date of Amount % of Increase
Applications Hearing (Millions) Requested Order (Millions) Granted
PSC
Electric
Retail 01/03/89 $ 27.2 3.7% 07/03/89 $18.2* 67%*
Retail 12/07/92 $ 72.0** 11.4% 06/07/93 $60.5 84%
Transit
Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
*Reflects a rate reduction of $3.7 million on January 4, 1993 (see
discussion below) and excludes impact of rate reduction of $7.7
million on January 3, 1990 which corresponds to $7.7 million reduction
in cost-of-service resulting from NRC approval of extension of Summer
Station's operating life to 40 years.
** As modified
On June 7, 1993 the PSC issued an order on the Company's pending
electric rate proceeding allowing an authorized return on common
equity of 11.5%, resulting in a 7.4% annual increase in retail
electric rates, or a projected $60.5 million annually based on a test
year. These rates are to be implemented in two phases over a two-year
period: phase one, effective June 1993, producing $42.0 million
annually, and phase two, effective June 1994, producing $18.5 million
annually, based on a test year. The Company's request, as modified,
had proposed a return on equity of 12.05% and had projected annual
increases of $53.0 million and $19.0 million for phases one and two,
respectively.
On 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 on October 5, 1992. The Company has appealed
the PSC's order to the Circuit Court. During oral arguments in
February 1994 the Circuit Court retained jurisdiction and remanded the
decision to the PSC for the limited purpose of answering questions
concerning the applicable regulatory principles used by the PSC in
determining these transit rates.
Since November 1, 1991 the Company's gas rate schedules for its
residential, small commercial and small industrial customers have
included a weather normalization adjustment (WNA). The WNA minimizes
fluctuations in gas revenues due to abnormal weather conditions and
has been approved through November 1994 subject to an annual review by
the PSC. The PSC order was based on a return on common equity of
12.25%. The WNA became effective the first billing cycle in December
1991.
In May 1989 the PSC approved a volumetric and direct billing
method for Pipeline Corporation to recover take-or-pay costs incurred
from its interstate pipeline suppliers pursuant to FERC-approved final
and non-appealable settlements. In December 1992 the Supreme Court
approved Pipeline Corporation's full recovery of the take-or-pay
charges imposed by its suppliers and treatment of these charges as a
cost of gas. However, the Supreme Court declared the PSC-approved
"purchase deficiency" methodology for recovery of these costs to be
unlawful retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. The Company believes that the
elimination of the purchase deficiency method of recovery will affect
the timing for recovery of take-or-pay charges and shift the
allocations among Pipeline Corporation's customers (including the
Company) but that all such charges should be ultimately recovered.
The Supreme Court decision establishes a principle of law that will
provide a basis for full recovery by the Company, as well as Pipeline
Corporation, of these costs.
14
On July 3, 1989 the PSC granted the Company approximately $21.9
million of a requested $27.2 million annual increase in retail
electric revenues based upon an allowed return on common equity of
13.25%. The Consumer Advocate appealed the decision to the Supreme
Court which, on August 31, 1992, found that the evidence in the
record of that case did not support a return on common equity
higher than 13.0% and remanded to the PSC a portion of its July
1989 order for a determination of the proper return on common
equity consistent with the Supreme Court's opinion. On January 19,
1993 the PSC issued an order allowing a return on common equity of
13.0%, approving a refund based on the difference in rates created
by the difference between the 13.0% and the 13.25% return on common
equity and making other non-material adjustments to the calculation
of cost-of-service. The total refund before interest and income
taxes, was approximately $14.6 million and was charged against 1992
"Electric Revenues." The refund plus interest was made during
1993.
On November 28, 1989 the PSC granted the Company an increase in
firm retail natural gas rates, effective November 30, 1989,
designed to increase annual revenues by $10.1 million, or 89.5%
out of the requested increase of approximately $11.3 million. In
its order the PSC authorized a 12.75% return on common equity. The
Consumer Advocate appealed to the Supreme Court which on August 31,
1992 remanded the order to the PSC for redetermination of the
proper amount of litigation expenses to include in the test period.
In January 1993 the PSC reduced the amount of litigation expense
and ordered a refund totaling approximately $163,000 which was
charged against 1992 "Gas Revenues." The refund was made during
1993.
Fuel Cost Recovery Procedures
The PSC has established a fuel recovery procedure which
determines the fuel component in the Company's retail electric base
rates semiannually based on projected fuel costs for the ensuing
six-month period, adjusted for any overcollection or
undercollection from the preceding six-month period. The Company
has the right to request a formal proceeding at any time should
circumstances dictate such a review.
In the April 1993 semiannual review of the fuel cost component
of electric rates, the PSC voted to reduce the rate from 13.5 mills
per KWH to 13.0 mills per KWH, a monthly decrease of $.50 for an
average customer using 1,000 KWH a month. This reduction coincided
with the retail electric rate case effective June 1993. For the
October 1993 review the PSC voted to continue the rate of 13.0
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 1993 review the PSC authorized an increase in
the base cost of gas from 41.963 cents per therm to 47.100 cents
per therm which resulted in a monthly increase of $5.14 (including
applicable taxes) based on an average of 100 therms per month on a
residential bill during the heating season.
In July 1990 the PSC initiated proceedings for a generic
hearing on the Industrial Sales Program Rider (ISPR) for the
Company and Pipeline Corporation. The PSC issued an order dated
December 20, 1991 approving a Stipulation and Agreement signed in
December 1991 by all parties involved which retained the ISPR with
modifications to Pipeline Corporation's gas cost mechanisms.
15
ENVIRONMENTAL CONTROL MATTERS
General
Federal and state authorities have imposed environmental
control requirements relating primarily to air emissions,
wastewater discharges and solid, toxic and hazardous waste
management. The Company is attempting to ensure that its
operations meet applicable environmental regulations and standards.
It is difficult to forecast the ultimate effect of environmental
quality regulations upon the existing and proposed operations.
Moreover, developments in these and other areas may require that
equipment and facilities be modified, supplemented or replaced.
Capital Expenditures
In the years 1991 through 1993, capital expenditures for
environmental control amounted to approximately $73.6 million. In
addition, approximately $7.4 million, $5.7 million and $4.8 million
of environmental control expenditures were made during 1993, 1992
and 1991, respectively, which were included in "Other operation"
and "Maintenance" expenses. It is not possible to estimate all
future costs for environmental purposes, but forecasts for minimum
capitalized expenditures are $40.3 million for 1994 and $252.1
million for the four-year period 1995 through 1998. These
expenditures are included in the Company's construction program.
Air Quality Control
The Federal Clean Air Act of 1970 (the "1970 Act") requires
that electric generating plants comply with primary and secondary
ambient air quality standards with respect to certain air
pollutants including particulates, sulfur oxides and nitrogen
oxides and imposes economic penalties for noncompliance. This Act
was amended with the passage of the Clean Air Act Amendments of
1990.
Currently, the Company uses a variety of methods to comply
with the State Implementation Plan (developed pursuant to the 1970
Act), including the use of low sulfur fuel, fuel switching,
reduction of load during periods when compliance cannot be met at
full power, maintenance and improvement of existing electrostatic
precipitators and the installation of new baghouses. The Company
and GENCO have been able to purchase sufficient fuel meeting
current sulfur standards for all of their plants. With respect to
sulfur dioxide emissions, none of the Company's electric
generating plants is included among the Phase I plants listed in
the Clean Air Act Amendments of 1990 with a compliance date of
January 1, 1995. Both companies will, however, be affected by
Phase II requirements which have a compliance date of January 1,
2000. The companies undertook a study in 1992 to determine the
most cost effective mix of control options to meet the requirements
of the Clean Air Act. Such a control strategy will most likely
result in requiring the Company to utilize a combination of the
following alternatives to meet its compliance requirements: (1)
burn lower sulfur coal, (2) burn natural gas, (3) retrofit at least
one coal-fired electric generating unit with a scrubber to remove
sulfur dioxide and (4) purchase sulfur dioxide emission allowances
to the extent necessary. In addition, the Company will install on
most of its coal-fired units low nitrogen oxide burners to reduce
nitrogen oxide emissions.
The Company currently estimates that, excluding GENCO, air
emissions control equipment will require capital expenditures of
$190 million over the 1994-1998 period to retrofit existing
facilities and an increased operation and maintenance cost of $22
million per year. Total capital expenditures required to meet
compliance requirements through the year 2003 are anticipated to be
approximately $211 million.
16
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 generating units.
Commensurate with renewal of these permits has been implementation
of a more rigorous control program on behalf of the permitting
agency. The facilities have been developing compliance plans to
meet the additional parameters of control and compliance has
involved updating wastewater treatment technologies. Amendments to
the Clean Water Act proposed recently in Congress include several
provisions which could prove costly to the Company. These include
limitations to mixing zones and the implementation of technology-
based standards.
Superfund Act and Environmental Assessment Program
As described in Note 1L 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,
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 significantly differ from the original
estimates. Amounts estimated and accrued to date ($19.6 million)
for site assessments and cleanup relate primarily to regulated
operations; such amounts have been deferred and are being amortized
and recovered through rates over a ten-year period. Estimates to
date include, among other things, the costs estimated to be
associated with the matters discussed in the following paragraphs.
The Company and SCANA each own two decommissioned manufactured
gas plant sites which contain residues of by-product chemicals.
The Company and SCANA have each maintained an active review of
their respective 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 18 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 potentially responsible parties (PRP) 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 investigations 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. Actual field work began November 1, 1993 after final
approval and authorization was granted by EPA. The Company is
also working with the City of Charleston to investigate potential
contamination from the manufactured gas plant at the city's
aquarium site.
During 1993 the Company settled its obligations at the Yellow
Water Road Superfund Site near Jacksonville, Florida, the Spencer
Transformer and Equipment Site in West Virginia and Elliott's Auto
Parts in Benton, Arkansas. No further expenses are anticipated for
these sites.
The Company has been listed as a PRP and has recorded
liabilities, which are not considered material, for the Macon-
Dockery waste disposal site near Rockingham, North Carolina, the
Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a
landfill owned by Lexington County in South Carolina.
17
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of
1991 requires promulgation of regulations addressing specified
subjects, one of which affects the management of industrial solid
waste. This regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation, if adopted as a final regulation in its present form,
could significantly impact the Company's engineering, design and
operation of existing and future ash management facilities.
Potential cost impacts could be substantial.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 (the "1982 Act") requires
that the Federal Government make available by 1998 a permanent
repository for high-level radioactive waste and spent nuclear
fuel and imposes a fee of 1.0 mill 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 fuel storage capability until at least
2008 and expects to be able to expand its storage capacity over the
life of Summer Station 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.
The 1982 Act also imposes on utilities the primary
responsibility for storage of their spent nuclear fuel until the
repository is available. (See "Fuel Supply" under "Electric
Operations" for a discussion of spent fuel storage facilities at
Summer Station.)
OTHER MATTERS
With regard to the Company's insurance coverage for Summer
Station, reference is made to Note 10B of Notes to Consolidated
Financial Statements, which is incorporated herein by reference.
ITEM 2. PROPERTIES
Reference is made to Schedule V - Property Plant and
Equipment, pages 54 through 59, for information concerning
investments in utility plant and nonutility property. 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.
18
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 590,000
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 26,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (3) Gas/Oil Parr, SC 1970 60,000
Williams (4) 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 (5) 3,304,000
(1) Summer rating.
(2) Represents the Company's two-thirds portion of the Summer
Station.
(3) 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.
(4) The two gas turbines at Williams are leased and have a net
capability of 49,000 KW. This lease expires on June 29,
1997.
(5) Excludes Williams Station.
The Company owns 424 substations having an aggregate
transformer capacity of 18,624,780 KVA. The transmission system
consists of 3,033 miles of lines and the distribution system
consists of 15,186 pole miles of overhead lines and 3,006 trench
miles of underground lines.
GAS
Natural Gas
The Company's gas system consists of approximately 6,179 miles
of three-inch equivalent distribution pipelines and approximately
10,085 miles of distribution mains and related service facilities.
The gas system acquired by SCANA is operated by the Company
and consists of approximately 450 miles of three-inch equivalent
distribution pipelines and approximately 778 miles of distribution
mains and related service facilities. Effective January 1, 1994
the assets and liabilities of such gas system were transferred from
SCANA to the Company.
19
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.
TRANSIT
The Company owns 93 motor coaches which operate on a route
system of 285 miles.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1.,
"BUSINESS," 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 STOCK AND RELATED
SECURITY HOLDER MATTERS
All of the Company's common stock is owned by SCANA and
therefore there is no market for such stock. During 1993 and 1992
the Company paid $108.6 million and $96.6 million, respectively, in
cash dividends to SCANA.
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, 1993 approximately $10.6
million of retained earnings were restricted as to payment of cash
dividends on common stock.
20
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1993 1992 1991 1990 1989
STATEMENT OF INCOME DATA (Thousands of Dollars except statistics)
Operating Revenues:
Electric $ 940,547 $ 829,938 $ 867,685 $ 851,676 $ 842,059
Gas 174,035 160,820 150,788 147,794 153,206
Transit 3,851 3,623 3,869 4,033 4,102
Total Operating Revenues 1,118,433 994,381 1,022,342 1,003,503 999,367
Operating Expenses:
Fuel used in electric generation
and purchased power 275,298 242,122 262,756 254,489 271,936
Gas purchased for resale 107,722 95,854 93,179 94,358 107,148
Other operation and maintenance 268,233 260,098 248,601 243,735 233,068
Depreciation and amortization 101,220 97,064 91,618 87,021 92,495
Taxes 146,641 116,976 129,482 125,954 109,641
Total Operating Expenses 899,114 812,114 825,636 805,557 814,288
Operating Income 219,319 182,267 196,706 197,946 185,079
Other Income:
Allowance for equity funds used
during construction 7,496 4,577 2,966 1,308 1,931
Other (911) (1,571) 317 (2,267) 1,399
Total Other Income 6,585 3,006 3,283 (959) 3,330
Income Before Interest Charges 225,904 185,273 199,989 196,987 188,409
Interest Charges (Credits):
Interest 85,222 86,994 81,340 79,481 78,670
Allowance for borrowed funds used
during construction (5,286) (3,884) (4,187) (3,333) (3,934)
Total Interest Charges, Net 79,936 83,110 77,153 76,148 74,736
Net Income 145,968 102,163 122,836 120,839 113,673
Dividends on Preferred Stock 6,217 6,474 6,706 6,911 7,263
Earnings Available for Common Stock $ 139,751 $ 95,689 $ 116,130 $ 113,928 $ 106,410
BALANCE SHEET DATA
Utility Plant, Net $2,687,193 $2,503,201 $2,380,761 $2,270,182 $2,185,505
Total Assets $3,189,939 $2,890,953 $2,748,580 $2,625,407 $2,529,659
Capitalization:
Common equity $1,051,334 $ 963,741 $ 840,505 $ 821,373 $ 774,909
Preferred stock:
Not subject to purchase
or sinking funds 26,027 26,027 26,027 26,027 26,027
Subject to purchase or
sinking funds, Net 52,840 56,154 59,469 62,704 66,099
Long-term debt
(excludes current portion) 1,097,043 945,964 993,674 779,524 802,328
Total Capitalization $2,227,244 $1,991,886 $1,919,675 $1,689,628 $1,669,363
OTHER STATISTICS
Electric:
Customers (Year-End) 468,901 461,928 453,687 446,544 435,033
Territorial Sales (Million KWH) 16,889 15,801 15,702 15,394 14,896
Residential:
Average annual use per customer (KWH) 14,077 13,037 13,246 13,330 12,891
Average annual rate per KWH $.0707 $.0695 $.0700 $.0707 $.0699
Gas:
Customers (Year-End) 221,278 218,582 214,485 210,326 205,471
Sales (Thousand Therms) 267,335 256,495 247,483 252,373 268,915
Residential:
Average annual use per
customer (therms) 606 577 522 497 575
Average annual rate per therm $.76 $.74 $.77 $.77 $.69
Transit:
Number of Coaches 93 95 102 109 113
Revenue Passengers Carried (Thousands) 4,568 5,837 6,395 6,788 6,430
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 demands 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 based on historical costs. As customer
growth and inflation occur and the Company expands its
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 relief.
Due to continuing customer growth, 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 in Orangeburg County. Construction of the plant
began in November 1992 with commercial operation expected in late
1995 or early 1996. The estimated price of the Cope plant,
excluding financing costs and AFC but including an allowance for
escalation, is $450 million. In addition, the transmission lines
for interconnection with the Company's system are expected to
cost $26 million. Until the completion of the new plant, the
Company is contracting for additional capacity as necessary to
ensure that the energy demands of its customers can be met.
As discussed in Note 2A of Notes to Consolidated Financial
Statements on June 7, 1993 the PSC issued an order granting the
Company a 7.4% annual increase in retail electric rates to be
implemented in two phases of $42.0 million annually effective
June 1993 and $18.5 million annually effective June 1994.
The estimated primary cash requirements for 1994, excluding
requirements for fuel liabilities and short-term borrowings, and
the actual primary cash requirements for 1993 are as follows:
1994 1993
(Thousands of Dollars)
Property additions and construction
expenditures, excluding allowance for
funds used during construction (AFC) $384,287 $280,910
Nuclear fuel expenditures 28,064 7,177
Maturing obligations, redemptions and
sinking and purchase fund requirements 5,024 3,700
Total $417,375 $291,787
Approximately 20.0% of total cash requirements (excluding
dividends) was provided from internal sources in 1993 as compared
to 49.2% in 1992.
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 12
consecutive months out of the 15 months prior to the month of
issuance is at least twice the annual interest requirements on
all Class A Bonds to be outstanding (Bond Ratio). For the year
ended December 31, 1993 the Bond Ratio was 3.70. The issuance of
additional Class A Bonds is restricted also to an additional
principal amount equal to 60% of unfunded net property additions
(which unfunded net property additions totaled approximately
$219.9 million at December 31, 1993), Class A Bonds issued on the
basis of retirements of Class A Bonds (which retirement credits
totaled $10.9 million at December 31, 1993) and Class A Bonds
issued on the basis of cash on deposit with the Trustee.
22
The Company has placed a new bond indenture (New Mortgage)
dated April 1, 1993 on substantially all of its electric
properties under which its future mortgage-backed debt (New
Bonds) will be issued. New Bonds are expected to be 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 $157 million were
available for such purpose as of December 31, 1993), 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 12 consecutive months out of the 18 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, 1993 the New Bond
Ratio was 5.0.
On April 29, 1993 the Securities and Exchange Commission
declared effective a registration statement for the issuance of
up to $700 million of New Bonds. The following series,
aggregating $600 million, have been issued under such
registration statement:
On June 9, 1993, $100 million, 7 5/8% Series due June 1,
2023 to repay short-term borrowings in a like amount.
On July 1, 1993, $100 million, 6% Series due June 15, 2000,
and $150 million, 7 1/8% Series due June 15, 2013, and on
July 20, 1993, $150 million, 7 1/2% Series due June 15,
2023, to redeem, on July 20, 1993, $382,035,000 of First and
Refunding Mortgage Bonds maturing between 1999 and 2017
and bearing interest at rates between 8% and 9 7/8% per
annum.
On December 20, 1993, $100 million, 6 1/4% Series due
December 15, 2003 to repay short-term borrowings in a like
amount.
On June 1, 1993 the Company redeemed the following amounts
of First and Refunding Mortgage Bonds: $35 million, 10 1/8%
Series due 2009 and $13 million, 9 7/8% Series due 2009.
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 FERC authority to issue short-term
indebtedness. The FERC ha authorized the Company to issue up to
$200 million of unsecured promissory notes or commercial paper
with maturity dates of 12 months or less but not later than
December 31, 1995.
The Company has $127.0 million authorized and unused lines
of credit at December 31, 1993. In addition, the Company has a
credit agreement for a maximum of $75 million to finance nuclear
and fossil fuel inventories, with $38.2 million available at
December 31, 1993.
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 12 consecutive months immediately preceding the
month of issuance is 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, 1993 the Preferred Stock Ratio was 2.52.
The Company anticipates that its 1994 cash requirements of
$417.4 million will be met primarily through internally generated
funds (approximately 32% excluding dividends), the sales of
additional securities, additional equity contributions from SCANA
and the incurrence of additional short-term and long-term
indebtedness. The timing and amount of such financing will
depend upon market conditions and other factors. Actual 1994
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.
23
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 has a compliance date of January 1,
1995 and the second, January 1, 2000. The Company meets all
requirements of Phase I and therefore will not have to implement
changes until compliance with Phase II requirements is necessary.
The Company then will most likely meet its compliance
requirements through the burning of natural gas and/or lower
sulfur coal, the addition of scrubbers to coal-fired generating
units, and the purchase of sulfur dioxide emission allowances.
Low nitrogen oxide burners will be installed to reduce nitrogen
oxide emissions.
The Company is continuing to refine a detailed compliance
plan that must be filed with the EPA by January 1, 1996. The
Company currently estimates that, excluding GENCO, air emissions
control equipment will require capital expenditures of $190
million over the 1994-1998 period to retrofit existing facilities
and an increased operation and maintenance cost of $22 million
per year. Total capital expenditures required to meet compliance
requirements through the year 2003 are anticipated to be
approximately $211 million.
The South Carolina Solid Waste Policy and Management Act of
1991 requires promulgation of regulations addressing specified
subjects, one of which affects the management of industrial solid
waste. This regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation, if adopted as a final regulation in its present form,
could significantly impact the Company's engineering, design and
operation of existing and future ash management facilities.
Potential cost impacts could be substantial.
As described in Note 1L 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, 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 significantly
differ from the original estimates. Amounts estimated and
accrued to date ($19.6 million) for site assessments and cleanup
of regulated operations have been deferred and are being
amortized and recovered through rates over a ten year period.
Estimates to date include, among other things, the costs
estimated to be associated with the matters discussed in the
following paragraphs.
The Company and SCANA each own two decommissioned
manufactured gas plant sites which contain residues of by-product
chemicals. The Company and SCANA have each maintained an active
review of their respective 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 18 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 potentially
responsible parties (PRP) 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 investigations 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. Actual field work began November 1, 1993 after
final approval and authorization was granted by EPA. The
Company is also working with the City of Charleston to
investigate potential contamination from the manufactured gas
plant at the city's aquarium site.
During 1993 the Company settled its obligations at the Yellow
Water Road Superfund Site near Jacksonville, Florida, the Spencer
Transformer and Equipment Site in West Virginia and Elliott's
Auto Parts in Benton, Arkansas. No further expenses are
anticipated for these sites.
The Company has been listed as a PRP and has recorded
liabilities, which are not considered material, for the Macon-
Dockery waste disposal site near Rockingham, North Carolina, the
Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a
landfill owned by Lexington County in South Carolina.
24
Litigation
In January 1994 the Company, acting on behalf of itself and
the PSA (as co-owners of Summer Station), reached a settlement
with Westinghouse Electric Corporation (Westinghouse) resolving a
dispute involving steam generators provided by Westinghouse to
Summer Station which are defective in design, workmanship and
materials. Terms of the settlement are confidential by agreement
of the parties and order of the court. The Company had filed an
action in May 1990 against Westinghouse in the U. S. District
Court for South Carolina; an order dismissing this suit
was issued on January 12, 1994.
Regulatory Matters
On June 7, 1993 the PSC issued an order on the Company's
pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually on a
test year basis. These rates are to be implemented in two
phases over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, on a test year basis.
The Company's operations are likely to be impacted by NEPA
and FERC Order 636. NEPA is designed to create a more
competitive wholesale power supply market by creating "exempt
wholesale generators" and allowing for the potential requirement
that a utility owning transmission facilities provide
transmission access to wholesalers. Order No. 636 is 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 will be able to meet successfully the
challenges of these altered business climates.
Other
In November 1992 the Financial Accounting Standards Board
issued Statement No. 112 "Employers' Accounting for
Postemployment Benefits." The Statement, which is effective for
calendar year 1994, establishes certain conditions for the
recognition of costs of benefits to former employees after
employment but before retirement. The Statement requires
recognition of the obligation to provide postemployment benefits
if such obligation is attributable to services previously
rendered, the obligation relates to rights which vest, payment of
the benefits is probable and the amount of such benefits can be
reasonably estimated. The Company does not anticipate that
application of this Statement will have a significant impact on
results of operations or financial position.
RESULTS OF OPERATIONS
Overview
Net income and the percent increase (decrease) from the
previous year for the years 1993, 1992 and 1991 were as follows:
1993 1992 1991
Net income $145,968 $102,163 $122,836
Percent increase (decrease) in net
income 42.9% (16.8%) 1.7%
1993 Net income increased for 1993 primarily due to an
increase in the electric margin which more than offset
increases in other operating expenses.
1992 Net income for 1992 decreased from 1991 primarily
due to the recording of an $11.1 million (after
interest and income taxes) reserve against earnings related
to the August 31, 1992 retail electric rate ruling from the
South Carolina Supreme Court (see Note 2E of Notes to
Consolidated Financial Statements) and as a result of
increased non-fuel operating expenses and interest charges.
The Company's financial statements include AFC. AFC is a
utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is
shown on the balance sheet as construction work in progress) is
capitalized. Both an equity and debt portion of AFC are included
in nonoperating income as noncash items which have the effect of
increasing reported net income. AFC represented approximately
5.6% of income before income taxes in 1993, 5.5% in 1992 and 3.7%
in 1991.
25
Electric Operations
Electric sales margins for 1993, 1992 and 1991 were as
follows:
1993 1992 1991
(Millions of Dollars)
Electric revenues $940.2 $844.5 $867.7
Provision for rate refunds .3 (14.6) -
Net Electric operating revenues 940.5 829.9 867.7
Less: Fuel used in electric generation 164.2 161.7 160.6
Purchased power 111.1 80.4 102.1
Margin $665.2 $587.8 $605.0
1993 The increase in electric sales margin from 1992 to
1993 is primarily a result of increased residential and
commercial KWH sales due to weather and customer growth, an
increase in retail electric rates beginning in June 1993,
and a $14.6 million reserve recorded in 1992 as discussed
below.
1992 The 1992 electric sales margin decreased from
1991 primarily due to the recording of a $14.6 million
reserve, before interest and income taxes, related to the
August 31, 1992 ruling from the Supreme Court (see Note 2E
of Notes to Consolidated Financial Statements) and a $1.9
million billing-related litigation settlement included in
1991 electric operating revenues.
Increases (decreases) in megawatt hour (MWH) sales volume by
classes are presented in the following table:
Increase (Decrease)
From Prior Year
Volume (MWH)
Classification 1993 1992
Residential 494,874 2,380
Commercial 305,560 37,749
Industrial 203,178 49,248
Sale for Resale (excluding interchange) 59,611 12,945
Other 24,873 (3,116)
Total territorial 1,088,096 99,206
Interchange 121,013 16,558
Total 1,209,109 115,764
Warmer weather and an increase in the number of electric
customers contributed to an all-time peak demand record of
3,557 MW (including Williams Station) on July 29, 1993. The
previous year's record of 3,380 MW was set on July 13, 1992.
Gas Operations
Gas sales margins for 1993, 1992 and 1991 were as follows:
1993 1992 1991
(Millions of Dollars)
Gas revenues $174.0 $160.8 $150.8
Less: Gas purchased for resale 107.7 95.8 93.2
Margin $ 66.3 $ 65.0 $ 57.6
1993 The 1993 gas sales margin increased from 1992
primarily as a result of increases in higher margin
residential and regular commercial sales.
1992 The 1992 gas sales margin increased from 1991
primarily due to recoveries of $4.2 million allowed under a
weather normalization adjustment, increases in residential
usage due to unseasonably cool weather during May 1992, and
increased transportation volumes.
26
Increases (decreases) in dekatherm (DT) sales volume by
classes are presented in the following table:
Increase (Decrease)
From Prior Year
Volume (DT)
Classification 1993 1992
Residential 723,356 1,303,673
Commercial (186,529) 22,188
Industrial 547,193 (424,657)
Total 1,084,020 901,204
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including
taxes, are presented in the following table:
Increase (Decrease)
From Prior Year
Classification 1993 1992
(Millions of Dollars)
Other operation and maintenance $ 8.1 $11.5
Depreciation and amortization 4.2 5.4
Income taxes 29.9 (17.2)
Other taxes (.2) 4.7
Total $42.0 $ 4.4
1993 Other operation and maintenance expenses increased for
1993 primarily due to the implementation of Financial
Accounting Standards Board Statement No. 106 (See Note 1J
of Notes to Consolidated Financial Statements) pursuant to
the June 1993 PSC electric rate order and the amortization
of environmental expenses. The depreciation and
amortization increase reflects additions to plant in
service. The increase in income taxes corresponds to the
increase in the corporate tax rate from 34% to 35%
retroactive to January 1, 1993.
1992 Other operation and maintenance expenses increased for
1992 primarily due to increases in administrative and
general expense, increase in nuclear regulatory fees, and
nuclear and transmission system maintenance. The increase
in depreciation and amortization expense reflects
additions to plant in service. The decrease in income tax
expense is primarily related to the tax impact of the rate
refund (see Note 2E of Notes to Consolidated Financial
Statements) and to other decreases in income. The
increase in other taxes is primarily due to higher
property taxes caused by property additions and increased
millage rates. In addition to the above, other taxes
increased due to increases in state license fees.
Interest Expense
1993 Interest expense, excluding the debt component of
AFC, decreased approximately $1.8 million primarily due to
the redemption of First and Refunding Mortgage Bonds and
the issuance of First Mortgage Bonds at lower interest
rates and the 1992 interest on the provision for rate
refund which were partially offset by interest on an
adjustment for the 1987-1988 income tax audit.
1992 Interest expense increased approximately $5.7
million in 1992 compared to 1991 due to the issuances of
the $145 million and $155 million of First and
Refunding Mortgage Bonds on July 24, 1991 and August 29,
1991, respectively, which more than offset the decreases
in interest expense resulting from the repayment of debt
and lower interest rates on remaining debt and interest of
$3.1 million accrued on the provision for rate refund (see
Note 2E of Notes to Consolidated Financial Statements).
27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditor's Report....................................... 29
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1993 and 1992... 30
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1993, 1992 and 1991............. 32
Consolidated Statements of Cash Flows for the years ended
December 31, 1993, 1992 and 1991............................. 33
Consolidated Statements of Capitalization as of
December 31, 1993 and 1992................................... 34
Notes to Consolidated Financial Statements..................... 36
Supplemental Financial Statement Schedules:
Schedule V - Property, Plant and Equipment for the
years ended December 31, 1993, 1992 and 1991................. 54
Schedule VI - Accumulated Depreciation and Amortization
of Property, Plant and Equipment for the years
ended December 31, 1993, 1992 and 1991....................... 57
Supplemental financial statement schedules other than those listed above
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.
28
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 of December 31, 1993 and 1992 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, 1993. Our audits also included the financial
statement schedules listed in the index on page 28. These
financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements and
financial statement schedules 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, 1993 and 1992 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1993 in conformity with generally
accepted accounting principles. Also, in our opinion, such
financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in
all material respects the information set forth therein.
s/Deloitte & Touche
DELOITTE & TOUCHE
Columbia, South Carolina
February 7, 1994
29
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1993 1992
(Thousands of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $3,067,881 $2,954,064
Gas 272,506 263,675
Transit 3,769 3,287
Common 72,804 65,124
Total 3,416,960 3,286,150
Less accumulated depreciation and amortization 1,097,531 1,039,939
Total 2,319,429 2,246,211
Construction work in progress 338,677 217,074
Nuclear fuel, net of accumulated amortization 29,087 39,916
Utility Plant, Net 2,687,193 2,503,201
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 12,709 12,604
Current Assets:
Cash and temporary cash investments (Note 8) 193 24,302
Receivables - customer and other 119,296 91,279
Receivables - affiliated companies (Note 1) 244 341
Inventories (at average cost):
Fuel (Notes 1, 3 and 4) 31,192 32,697
Materials and supplies 43,372 43,268
Prepayments 10,089 12,189
Accumulated Deferred Income Taxes 9,015 -
Total Current Assets 213,401 204,076
Deferred Debits:
Unamortized debt expense 11,060 8,354
Accumulated deferred income taxes (Notes 1 and 7) - 36,757
Unamortized deferred return on plant investment (Notes 1 and 2) 14,860 19,106
Nuclear plant decommissioning fund (Note 1) 25,103 20,841
Other (Note 1) 225,613 86,014
Total Deferred Debits 276,636 171,072
Total $3,189,939 $2,890,953
See Notes to Consolidated Financial Statements.
30
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1993 1992
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment (Note 5):
Common equity $1,051,334 $ 963,741
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,077,361 989,768
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 52,840 56,154
Long-Term Debt, Net (Notes 3, 4 and 8) 1,097,043 944,416
Advances from Affiliated Companies, Net (Note 3) - 1,548
Total Capitalization 2,227,244 1,991,886
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 1,011 33
Current portion of long-term debt (Note 3) 13,719 12,754
Current portion of preferred stock (Note 6) 2,504 2,485
Accounts payable 68,182 49,749
Accounts payable - affiliated companies (Note 1 and 3) 28,630 32,222
Estimated rate refunds and related interest (Note 2) 2,509 17,811
Customer deposits 12,207 12,918
Taxes accrued 39,965 51,127
Interest accrued 17,764 26,433
Dividends declared 29,982 28,353
Other 10,042 6,185
Total Current Liabilities 226,515 240,070
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 480,808 451,046
Accumulated deferred investment tax credits (Notes 1 and 7) 84,447 87,692
Accumulated reserve for nuclear plant decommissioning (Note 1) 25,103 20,841
Other (Note 1) 145,822 99,418
Total Deferred Credits 736,180 658,997
Commitments and Contingencies (Note 10) - -
Total $3,189,939 $2,890,953
See Notes to Consolidated Financial Statements.
31
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $ 940,547 $ 829,938 $ 867,685
Gas 174,035 160,820 150,788
Transit 3,851 3,623 3,869
Total Operating Revenues 1,118,433 994,381 1,022,342
Operating Expenses:
Fuel used in electric generation 164,187 161,691 160,640
Purchased power (including affiliated
purchases)(Note 1) 111,111 80,431 102,116
Gas purchased from affiliate for resale (Note 1) 107,722 95,854 93,179
Other operation 207,126 199,819 190,824
Maintenance 61,107 60,279 57,777
Depreciation and amortization (Note 1) 101,220 97,064 91,618
Income taxes (Notes 1 and 7) 81,280 51,382 68,543
Other taxes (Note 12) 65,361 65,594 60,939
Total Operating Expenses 899,114 812,114 825,636
Operating Income 219,319 182,267 196,706
Other Income (Note 1):
Allowance for equity funds used during construction 7,496 4,577 2,966
Other income (loss), net of income taxes (911) (1,571) 317
Total Other Income (Loss) 6,585 3,006 3,283
Income Before Interest Charges 225,904 185,273 199,989
Interest Charges (Credits):
Interest on long-term debt, net 79,410 80,217 74,250
Other interest expense (Note 1 and 3) 5,812 6,777 7,090
Allowance for borrowed funds used
during construction (Note 1) (5,286) (3,884) (4,187)
Total Interest Charges, Net 79,936 83,110 77,153
Net Income 145,968 102,163 122,836
Preferred Stock Cash Dividends (At stated rates) (6,217) (6,474) (6,706)
Earnings Available for Common Stock 139,751 95,689 116,130
Retained Earnings at Beginning of Year 262,262 265,864 246,734
Common Stock Cash Dividends Declared (Note 5) (110,300) (99,291) (97,000)
Retained Earnings at End of Year $ 291,713 $ 262,262 $ 265,864
See Notes to Consolidated Financial Statements.
32
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $145,968 $102,163 $122,836
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 101,370 97,212 91,805
Amortization of nuclear fuel 18,156 23,190 18,384
Deferred income taxes, net 56,982 (15,959) 29,680
Deferred investment tax credits, net (3,245) (3,245) (3,244)
Net regulatory asset - adoption of SFAS No. 109 (40,398) - -
Allowance for funds used during construction (12,782) (8,461) (7,153)
Unamortized loss on reacquired debt (17,094) (112) 139
Early retirements (11,840) - -
Nuclear refueling accrual (6,086) 11,862 (6,192)
Over (under) collections, fuel adjustment clause (13,728) 7,901 (1,236)
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (27,920) 4,319 (4,210)
(Increase) decrease in inventories 1,401 1,069 8,647
Increase (decrease) in accounts payable 16,757 2,526 (28,561)
Increase (decrease) in estimated rate
refunds and related interest (15,302) 17,811 -
Increase (decrease) in taxes accrued (11,162) 36 7,150
Increase (decrease) in interest accrued (8,669) 83 9,893
Other, net 886 (2,457) 6,071
Net Cash Provided From Operating Activities 173,294 237,938 244,009
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures (300,620) (243,329) (215,303)
Nonutility property and investments (248) (205) (447)
Principal noncash item:
Allowance for funds used during construction 12,782 8,461 7,153
Net Cash Used For Investing Activities (288,086) (235,073) (208,597)
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds 600,000 - 300,000
Equity contributions from parent 58,142 126,838 -
Other Long-term debt 2,562 - -
Repayments:
Mortgage bonds (430,000) (35,890) (8,000)
Other Long-term debt (405) (120) (75,285)
Preferred stock (3,295) (3,199) (2,622)
Dividend Payments:
Common stock (108,641) (96,550) (73,000)
Preferred stock (6,247) (6,558) (6,718)
Short-term borrowings, net 978 (20) (130,417)
Fuel financings, net (18,948) (6,628) (4,292)
Advances - affiliated companies, net (3,463) (2,899) (3,430)
Net Cash Provided From (Used For) Financing Activities 90,683 (25,026) (3,764)
Net Increase (Decrease) in Cash and Temporary Cash Investments (24,109) (22,161) 31,648
Cash and Temporary Cash Investments, January 1 24,302 46,463 14,815
Cash and Temporary Cash Investments, December 31 $ 193 $ 24,302 $ 46,463
Supplemental Cash Information:
Cash paid for - Interest $ 92,367 $ 86,093 $ 70,201
- Income taxes 79,612 72,584 38,313
Noncash Financing Activities:
Capital lease obligations recorded - - 2,864
Department of Energy Decontamination and Decommissioning Fund 4,965 - -
See Notes to Consolidated Financial Statements.
33
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1993 1992
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 188,713 130,624
Capital stock expense (debit) (5,497) (5,550)
Retained earnings 291,713 262,262
Total Common Equity 1,051,334 47% 963,741 48%
Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5):
$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1993 1992 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 1993 1992 Current Through Minimum
7.70% 92,992 96,000 101.00 - 101.00 9,299 9,600
8.12% 131,899 136,265 102.03 - 102.03 13,190 13,626
Total 224,891 232,265
$50 Par Value - Authorized - 1,639,886 shares
Shares Outstanding Redemption Price
Eventual
Series 1993 1992 Current Through Minimum
4.50% 20,800 22,400 51.00 - 51.00 1,040 1,120
4.60% 3,834 5,334 50.50 - 50.50 192 267
4.60%(A) 30,052 32,052 51.00 - 51.00 1,503 1,602
4.60%(B) 81,600 85,000 50.50 - 50.50 4,080 4,250
5.125% 74,000 75,000 51.00 - 51.00 3,700 3,750
6.00% 89,600 92,800 50.50 - 50.50 4,480 4,640
8.72% 160,000 192,000 51.00 12-31-98 50.00 8,000 9,600
9.40% 197,191 203,678 51.175 - 51.175 9,860 10,184
Total 657,077 708,264
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1993 and 1992
Total Pr
Less: Current portion, including sinking fund requirements 2,504 2,485
Total Preferred Stock, Net (Subject to purchase or sinking funds) 52,840 3% 56,154 3%
See Notes to Consolidated Financial Statements.
34
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1993 1992
(Thousands of Dollars)
Long-Term Debt (Notes 3, 4 and 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100,000 -
6 1/4% 2003 100,000 -
7 1/8% 2013 150,000 -
7 1/2% 2023 150,000 -
7 5/8% 2023 100,000 -
First and Refunding Mortgage Bonds:
Year of
Series Maturity
4 7/8% 1995 16,000 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
8% 1999 - 35,000
9 1/8% 1999 - 15,000
8% 2001 - 35,000
7 1/4% 2002 30,000 30,000
9% 2006 145,000 145,000
9 1/8% 2006 - 50,000
8.40% 2006 - 50,000
8 3/8% 2007 - 30,000
8.90% 2008 - 30,000
10 1/8% 2009 - 35,000
9 7/8% 2009 - 50,000
8 3/4% 2017 - 100,000
8 7/8% 2021 155,000 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,760 6,855
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
Capitalized Lease Obligations, due 1991-1997 (various rates between
5 3/4% and 10%) 2,897 4,875
Installment Note Payable, due 1996 2,277 -
Department of Energy Decontamination and Decommissioning Obligation 4,634 -
Nuclear and Fossil Fuel Liability 36,750 55,698
Total 1,116,803 960,913
Less: Current maturities, including sinking fund requirements 13,719 12,754
Unamortized discount 6,041 3,743
Total Long-Term Debt, Net 1,097,043 49% 944,416 48%
Advances from Affiliated Companies 1,559 5,023
Less: Current Portion of Advances - Affiliated Companies 1,559 3,475
Advances from Affiliated Companies, Net - - 1,548 -
Total Capitalization $2,227,244 100% $1,991,886 100%
See Notes to Consolidated Financial Statements.
35
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 accompanying Consolidated Financial Statements include
the accounts of the Company and South Carolina Fuel Company, Inc.
(Fuel Company) (see Note 1M). 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 South Carolina Pipeline
Corporation (Pipeline Corporation) and at December 31, 1993 and
1992 the Company had approximately $15.1 million and $15.2
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 South Carolina
Generating Company, Inc. (GENCO), under a unit power sales
agreement. At December 31, 1993 and 1992 the Company had
approximately $7.5 million and $4.5 million, respectively,
payable to GENCO for unit power purchases. Such unit power
purchases, which are included in "Purchased power," amounted to
approximately $98.1 million, $73.1 million and $92.3 million in
1993, 1992 and 1991, respectively.
Total interest income (based on market interest rates)
associated with the Company's advances to affiliated companies
was approximately $129,000, $231,000 and $141,000 in 1993, 1992
and 1991.
Included in "Other interest expense" for 1993, 1992 and 1991
is approximately $29,000, $16,000 and $830,000, respectively,
relating to advances from affiliated companies. Intercompany
interest is calculated at market rates.
B. 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
Public Service Commission of South Carolina (PSC).
C. 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 the 885 MW 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 $920.2 million and $916.0
million as of December 31, 1993 and 1992, respectively.
Accumulated depreciation associated with the Company's share of
Summer Station was approximately $285.3 million and $262.2
million as of December 31, 1993 and 1992, respectively. The
Company's share of the direct expenses associated with operating
Summer Station is included in "Other operation" and "Maintenance"
expenses.
36
D. Allowance for Funds Used During Construction
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, as a component of construction cost, of 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 rates of 9.4%,
9.4% and 9.8% for 1993, 1992 and 1991, respectively. These rates
do not exceed the maximum allowable rate as calculated under FERC
Order No. 561. Interest on nuclear fuel in process is
capitalized at the actual interest amount.
E. 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 1993, 1992 and 1991.
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 component in retail electric rates. The fuel component
contained in electric rates is established by the PSC during
semiannual fuel cost hearings. Any difference between actual
fuel cost and that contained in the fuel component is deferred
and included when determining the fuel cost component during the
next semiannual fuel cost hearing. At December 31, 1993 and
1992 the Company had overcollected through the electric fuel
clause component approximately $9.2 million and $17.7 million,
respectively, which are included in "Deferred Credits - Other."
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, 1993 and 1992 the Company had
undercollected through the gas cost recovery procedure
approximately $11.0 million and $5.7 million, respectively, which
are included in "Deferred Debits - Other."
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 2.97%, 3.00%,
and 2.97% for 1993, 1992 and 1991, 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 United
States Department of Energy under a contract for disposal of
spent nuclear fuel.
37
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
The expenditures (on a before-tax basis) related to the Company's
share of decommissioning activities are currently estimated (in
2022 dollars, assuming an annual 4.5% rate of inflation) to be
approximately $545.3 million including partial reclamation costs.
The Company is providing for its share of estimated
decommissioning costs over the life of Summer Station. The
Company collected through rates $2.5 million and $1.6 million in
1993 and 1992, respectively. The amounts collected are deposited
in 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.
In addition, pursuant to the National Energy Policy Act
passed by Congress in 1992, the Company has recorded a liability
for its estimated share of amounts required by the U. S.
Department of Energy for its decommissioning fund. SCE&G will
recover the costs associated with this liability, totaling $4.6
million at December 31, 1993, through the fuel cost component of
its rates; accordingly, these amounts have been deferred and are
included in "Deferred Debits-Other" and "Long-Term Debt, Net."
I. Income Taxes
The Company is included in the consolidated Federal and
State income tax returns filed by SCANA. Income taxes are
allocated to the Company based on its contribution to
consolidated taxable income.
The Company adopted Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," effective
January 1, 1993. Prior years' financial statements have not been
restated. Deferred tax assets and liabilities were adjusted from
the amounts recorded at December 31, 1992 under prior standards
to the amounts required at January 1, 1993 under Statement No.
109 at currently enacted income tax rates. The adjustments were
charged or credited to regulatory assets or liabilities if the
Company expects to recover the resulting additional income tax
expense from, or pass through the resulting reductions in income
tax expense to, customers of the Company; otherwise they were
charged or credited to income tax expense. The cumulative effect
of adopting Statement No. 109 on retained earnings as of January
1, 1993, as well as the effect of adoption on net income for the
year ended December 31, 1993, was not material. The combined
effect of adopting Statement No. 109 and adjusting deferred tax
assets and liabilities for the change in 1993 of the corporate
Federal income tax rate from 34% to 35% resulted in balances of
$97.0 million in regulatory assets (included in "Deferred Debits-
Other") and $56.6 million in regulatory liabilities (included in
"Deferred Credits-Other").
In accordance with Statement No. 109, deferred tax assets
and liabilities are recorded for the tax effect of temporary
differences between the book 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.
Prior to the adoption of Statement No. 109 on January 1,
1993, the Company recorded a deferred income tax provision on all
material timing differences between the inclusion of items in
pretax financial income and taxable income each year, except for
those which were expected to be passed through to, or collected
from, customers. Accumulated deferred income taxes were
generally not adjusted for changes in enacted tax rates.
J. 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.
38
Net periodic pension cost, as determined by an
independent actuary, for the years ended December 31,
1993, 1992 and 1991 included the following components:
1993 1992 1991
(Thousands of Dollars)
Service cost-benefits earned during the period $ 7,629 $ 7,174 $ 6,367
Interest cost on projected benefit obligation 20,413 19,628 18,334
Adjustments: Return on plan assets (50,389) (28,607) (51,440)
Net amortization and deferral 25,936 8,096 36,263
Amounts contributed by the Company's affiliates (175) (154) (1,177)
Net periodic pension cost of the Company $ 3,414 $ 6,137 $ 8,347
The following table sets forth the funded status of the plan, as determined
by an independent actuary, at December 31, 1993 and 1992:
1993 1992
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $204,794 $177,930
Nonvested benefit obligation 14,085 17,110
Accumulated benefit obligation $218,879 $195,040
Projected benefit obligation $295,718 $258,440
Plan assets at fair value
(invested primarily in
equity and debt securities) 351,648 304,114
Plan assets greater than
projected benefit obligation 55,930 45,674
Unrecognized net transition liability 10,713 11,555
Unrecognized prior service costs 9,294 10,563
Unrecognized net gain (64,607) (63,633)
Pension asset recognized
in SCANA's Consolidated Balance Sheets $ 11,330 $ 4,159
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 the amounts shown above for the
years 1993, 1992 and 1991.
1992 and
1993 1991
Annual discount rate used to determine benefit obligations 7.25% 8.0%
Expected long-term rate of return on plan assets 7.25% 8.0%
Discount rate used in determining pension cost 8.0% 8.0%
Assumed annual rate of future salary increases for projected
benefit obligation 4.75% 5.5%
The change in the annual discount rate used to determine
benefit obligations from 8.0% to 7.25% as of December 31, 1993
increased the projected benefit obligation and reduced the
unrecognized net gain by approximately $4.1 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active and
retired employees. On January 1, 1993 the Company adopted
Statement No. 106 "Employers' Accounting for Postretirement
Benefits Other Than Pensions." This Statement requires that the
cost of postretirement benefits other than pensions be accrued
during the years the employees render the service necessary to be
eligible for the applicable benefits. The Company previously
expensed these benefits, which are primarily health care, as
claims were incurred. The accumulated obligation for these
benefits at January 1, 1993 was approximately $68 million
(transition liability) and the annualized increase in expenses
(net of payments to current retirees), including the amortization
of the transition liability over approximately 20 years as
provided for by the Statement, is approximately $4.7 million. In
its June 1993 electric rate order (see Note 2A) the PSC approved
the inclusion in rates of the portion of increased expenses
related to electric operations. Such expenses had been deferred
through May 31, 1993 pursuant to a December 10, 1992 accounting
directive allowing deferral pending consideration of recovery in
future rate proceedings. For the year ended December 31, 1993
the Company expensed approximately $4.3 million, net of payments
to current retirees.
39
Net periodic postretirement benefit cost, as determined by
an independent actuary for the year ended December 31, 1993
included the following components (thousands of dollars):
Service cost-benefits earned during the period $ 1,908
Interest cost on accumulated postretirement benefit
obligation 5,502
Adjustments: Return on plan assets -
Amortization of unrecognized transition
obligation 3,344
Other net amortization and deferral -
Amounts contributed by the Company's affiliates (525)
Net periodic postretirement benefit cost $ 10,229
The following table sets forth the unfunded status of the plan, as determined
by an independent actuary, at December 31, 1993 (thousands of dollars):
Accumulated postretirement benefit obligations for:
Retirees $ 40,865
Other fully eligible participants 25,767
Other active participants 6,841
Accumulated postretirement benefit obligation 73,473
Plan assets at fair value -
Plan assets less accumulated postretirement benefit
obligation (73,473)
Unrecognized net transition liability 64,925
Unrecognized prior service costs -
Unrecognized net (gain) loss 4,248
Postretirement benefit liability recognized
in Consolidated Balance Sheet $ (4,300)
The accumulated postretirement benefit obligation is based upon the plan's
benefit provisions and the following assumptions:
Assumed health care cost trend rate used to
measure expected 1994 costs 12.25%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.25%
Discount rate used in determining post-
retirement benefit costs 7.25%
Assumed annual rate of salary increases 4.75%
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, 1993
and the accumulated postretirement benefit obligation as of
December 31, 1993 would be to increase such amounts by $60,000
and $1.7 million, respectively.
K. 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.
40
L. 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 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 significantly
differ from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have been deferred and are
being amortized and recovered through rates over a ten-year
period. Such amounts totaled $19.6 million and $18.3 million at
December 31, 1993 and 1992, respectively, and are included in
"Deferred Debits-Other."
M. Fuel Inventory
Nuclear fuel and fossil fuel inventories 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.
Accordingly, such fuel inventories and fuel-related assets and
liabilities are included in the Company's consolidated financial
statements (see Note 4).
N. Postemployment Benefits
In November 1992 the Financial Accounting Standards Board
issued Statement No. 112 "Employers' Accounting for
Postemployment Benefits." The Statement, which is effective for
calendar year 1994, establishes certain conditions for the
recognition of costs of benefits to former employees after
employment but before retirement. The Statement requires
recognition of the obligation to provide postemployment benefits
if such obligation is attributable to services previously
rendered, the obligation relates to rights which vest, payment of
the benefits is probable, and the amount of such benefits can be
reasonably estimated. The Company does not anticipate that
application of this Statement will have a significant impact on
results of operations or financial position.
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. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1993 presentation.
2. RATE MATTERS:
A. On June 7, 1993 the PSC issued an order on the Company's
pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually
based on a test year. These rates are to be implemented in two
phases over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, based on a test year.
B. On 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 on October 5,
1992. The Company has appealed the PSC's order to the Circuit
Court. During oral arguments in February 1994 the Circuit Court
retained jurisdiction and remanded the decision to the PSC for
the limited purpose of answering questions concerning the
applicable regulatory principles used by the PSC in determining
these transit rates.
C. Since November 1, 1991 the Company's gas rate schedules
for its residential, small commercial and small industrial
customers have included a weather normalization adjustment. The
WNA minimizes fluctuations in gas revenues due to abnormal
weather conditions and has been approved through November 1994
subject to an annual review by the PSC. The PSC order was based
on a return on common equity of 12.25%. The PSC also approved
the WNA for SCANA's directly owned natural gas distribution
system which is operated by the Company. The WNA became effective
the first billing cycle in December 1991.
41
D. In May 1989 the PSC approved a volumetric and direct
billing method for Pipeline Corporation to recover take-or-pay
costs incurred from its interstate pipeline suppliers pursuant
to FERC-approved final and non-appealable settlements. In
December 1992 the Supreme Court approved Pipeline Corporation's
full recovery of the take-or-pay charges imposed by its suppliers
and treatment of these charges as a cost of gas. However, the
Supreme Court declared the PSC-approved "purchase deficiency"
methodology for recovery of these costs to be unlawful
retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. The Company believes that
the elimination of the purchase deficiency method of recovery
will affect the timing for recovery of take-or-pay charges and
shift the allocations among Pipeline Corporation's customers
(including the Company) but that all such charges should be
ultimately recovered. The Supreme Court decision establishes a
principle of law that will provide a basis for full recovery by
the Company, as well as Pipeline Corporation, of these costs.
E. On July 3, 1989 the PSC granted the Company approximately
$21.9 million of a requested $27.2 million annual increase in
retail electric revenues based upon an allowed return on common
equity of 13.25%. The Consumer Advocate appealed the decision to
the Supreme Court which, on August 31, 1992, found that the
evidence in the record of that case did not support a return on
common equity higher than 13.0% and remanded to the PSC a portion
of its July 1989 order for a determination of the proper return
on common equity consistent with the Supreme Court's opinion. On
January 19, 1993 the PSC issued an order allowing a return on
common equity of 13.0%, approving a refund based on the
difference in rates created by the difference between the 13.0%
and the 13.25% return on common equity and making other non-
material adjustments to the calculation of cost-of-service. The
total refund, before interest and income taxes, was approximately
$14.6 million, and was charged against 1992 "Electric Revenues."
The refund plus interest was made during 1993.
F. On November 28, 1989 the PSC granted the Company an
increase in firm retail natural gas rates, effective November 30,
1989, designed to increase annual revenues by $10.1 million, or
89.5% out of the requested increase of approximately $11.3
million. In its order the PSC authorized a 12.75% return on
common equity. The Consumer Advocate appealed to the Supreme
Court which on August 31, 1992 remanded the order to the PSC for
redetermination of the proper amount of litigation expenses to
include in the test period. In January 1993 the PSC reduced the
amount of litigation expense and ordered a refund totaling
approximately $163,000 which was charged against 1992 "Gas
Revenues." The refund was made during 1993.
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 1994 through 1998
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1994 $13,719 1997 $26,345
1995 28,943 1998 31,325
1996 64,146
Approximately $10.9 million of the current portion of long-
term debt for 1993 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.
During 1993 certain issues of the Company's First and
Refunding Mortgage Bonds were redeemed and replaced with First
Mortgage Bonds.
42
Pipeline Corporation's two principal gas suppliers have
incurred liabilities to gas producers under take-or-pay
provisions of gas supply contracts. The FERC has accepted
filings allowing these pipeline suppliers to recover portions of
such take-or-pay liabilities from their customers, including
Pipeline Corporation, through volumetric surcharges in gas rates
and through direct billings.
The Company's liability to Pipeline Corporation for its
proportionate share of take-or-pay costs was approximately $1.6
million at December 31, 1993 which is included in Accounts
Payable - Affiliated Companies. The Company is paying this
amount plus interest (9.4%) to Pipeline Corporation over a five-
year period which began June 1989. The Company recovers these
costs from its customers through the purchased gas adjustment
(PGA) provisions in its rates.
The Company's take-or-pay liability to Pipeline Corporation
will likely be increased due to the Supreme Court decision dated
December 14, 1992 (see Note 2D). The Company anticipates that
any such increase will be recovered through the PGA.
Certain outstanding long-term debt of an affiliated
company (approximately $35.9 million at December 31, 1993 and
1992 respectively) 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 are financed through the
issuance of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires July 31, 1996. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $75 million that may
be outstanding at any time.
Commercial paper outstanding totaled $36.8 million and $55.7
million at December 31, 1993 and 1992 at weighted average
interest rates of 3.47% and 3.81%, respectively.
43
5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not
Subject to
Purchase or Sinking Funds):
The changes in "Stockholders' Investment" (Including
Preferred Stock Not Subject to Purchase or Sinking Funds) during
1993, 1992 and 1991 are summarized as follows:
Common Preferred Thousands
Shares Shares of Dollars
Balance December 31, 1990 40,296,147 322,877 $847,400
Changes in Retained Earnings:
Net Income 122,836
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,706)
Common Stock (97,000)
Other 2
Balance December 31, 1991 40,296,147 322,877 866,532
Changes in Retained Earnings:
Net Income 102,163
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,474)
Common Stock (99,291)
Equity Contributions from Parent 126,838
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
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, 1993
approximately $10.6 million of retained earnings were restricted
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 under sinking fund requirements are at par values.
At any time when dividends have not been paid in full or
declared and set apart for payment on all series of preferred
stock, the Company may not redeem any shares of preferred stock
(unless all shares of preferred stock then outstanding are
redeemed) or purchase or otherwise acquire for value any shares
of preferred stock except in accordance with an offer made to all
holders of preferred stock. The Company may not redeem any
shares of preferred stock (unless all shares of preferred stock
then outstanding are redeemed) or purchase or otherwise acquire
for value any shares of preferred stock (except out of monies set
aside as purchase funds or sinking funds for one or more series
of preferred stock) at any time when it is in default under the
provisions of the purchase fund or sinking fund for any series of
preferred stock.
44
The aggregate annual amounts of purchase fund or sinking
fund requirements for preferred stock for the years 1994 through
1998 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1994 $2,504 1997 $2,440
1995 2,515 1998 2,440
1996 2,482
The changes in "Total Preferred Stock (Subject to Purchase or Sinking
Funds)" during 1993, 1992 and 1991 are summarized as follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1990 1,050,201 $ 64,460
Shares Redeemed:
$100 par value (628) (63)
$50 par value (51,169) (2,559)
Balance December 31, 1991 998,404 61,838
Shares Redeemed:
$100 par value (6,098) (610)
$50 par value (51,777) (2,589)
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
7. INCOME TAXES:
Total income tax expense for 1993, 1992 and 1991 is as follows:
1993 1992 1991
(Thousands of Dollars)
Current taxes:
Federal $60,577 $62,147 $36,594
State 6,822 7,852 4,833
Total current taxes 67,399 69,999 41,427
Deferred taxes, net:
Federal 12,197 (16,274) 25,212
State 4,387 (322) 4,469
Total deferred taxes 16,584 (16,596) 29,681
Investment tax credits:
Amortization of amounts
deferred (credit) (3,245) (3,245) (3,245)
Total income tax expense $80,738 $50,158 $67,863
45
Total income taxes differ from amounts computed by applying
the statutory Federal income tax rate of 35% for 1993 and 34% for
1992 and 1991 to pretax income as follows:
1993 1992 1991
(Thousands of Dollars)
Net income $145,968 $102,163 $122,836
Total income tax expense:
Charged to operating expenses 81,280 51,382 68,543
Charged (credited) to other income (542) (1,224) (680)
Total pretax income $226,706 $152,321 $190,699
Income taxes on above at statutory Federal
income tax rate $ 79,347 $ 51,789 $ 64,838
Increases (decreases) attributable to:
Allowance for funds used during construction
(excluding nuclear fuel) (2,624) (1,556) (1,009)
Deferred return on plant investment,
net of amortization 1,486 1,444 1,444
Depreciation differences 2,531 2,356 1,666
Amortization of investment tax credits (3,245) (3,245) (3,245)
State income taxes (less Federal
income tax effect) 7,286 4,970 6,140
Deferred income tax flowback at higher
than statutory rates (3,641) (4,914) (2,768)
Other differences, net (402) (686) 797
Total income tax expense $ 80,738 $ 50,158 $ 67,863
The Omnibus Budget Reconciliation Act was signed into law on
August 10, 1993, increasing the corporate tax rate from 34% to 35%
effective January 1, 1993. This impact of this change on the
Company's financial position and results of operation was not
material.
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $471.8
million at December 31, 1993 determined in accordance with Statement
No. 109 (see Note 1I) are as follows (thousands of dollars):
1993
Deferred tax assets:
Unamortized investment tax credits $ 52,310
Cycle billing 15,084
Nuclear operations expenses 4,908
Deferred compensation programs 5,265
Other postretirement benefits 1,631
Injuries and damages 724
Other 3,808
Total deferred tax assets 83,730
Deferred tax liabilities:
Accelerated depreciation and amortization 526,540
Reacquired debt 7,574
Property taxes 6,068
Pension expense 6,266
Nuclear system maintenance 2,965
Early retirement programs 1,961
Nuclear decontamination fund 1,417
Other 2,732
Total deferred tax liabilities 555,523
Net deferred tax liability $471,793
46
"Total deferred taxes" charged (credited) to income tax expense result from
timing differences in recognition of the following items:
1992 1991
(Thousands of Dollars)
Charged (credited) to expense:
Accelerated depreciation
and amortization $ (5) $22,053
Deferred fuel accounting (2,947) 461
Property taxes 493 1,608
Cycle billing (1,381) 3,608
Nuclear refueling accrual (4,430) 2,052
Electric rate refund (6,571) -
Injuries and damages (1,377) -
Other, net (378) (101)
Total deferred taxes $(16,596) $29,681
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 and 1991 Federal income tax returns. No 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.
8. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's
financial instruments at December 31, 1993 and 1992 are as follows:
1993 1992
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Cash and temporary cash investments $ 193 $ 193 $ 24,302 $ 24,302
Investments 62 62 62 62
Short-term borrowings 1,011 1,011 33 33
Total Long-term debt (including
advances from affiliated companies) 1,112,321 1,194,522 962,193 1,006,636
Total Preferred stock (subject to
purchase or sinking funds) 55,344 51,618 58,639 53,771
The information presented herein is based on pertinent information available
to the Company as of December 31, 1993 and 1992. 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, 1993, 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 for 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.
Short-term borrowings are valued at their carrying amount.
47
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 lines of credit.
Commercial paper borrowings are for 270 days or less. Details of lines of
credit and short-term borrowings at December 31, 1993, 1992 and 1991 and for
the years then ended are as follows:
1993 1992 1991
(Millions of dollars)
Authorized lines of credit at year end $127.0 $119.9 $121.7
Unused lines of credit at year-end $127.0 $119.9 $121.7
Short-term borrowings (including
commercial paper) during the year:
Maximum outstanding $126.0 $ 95.3 $130.4
Average outstanding $ 56.0 $ 40.9 $ 64.5
Weighted daily average interest rates:
Bank loans 3.24% 3.49% 7.69%
Commercial paper 3.13% 3.69% 6.31%
Short-term borrowings outstanding at
year-end:
Commercial paper $ 1.0 $ - $ -
Weighted average interest rate 3.50% - -
Bank loans $ - $ - $ -
Weighted average interest rate - - -
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 in Orangeburg County. Construction of the plant
began in November 1992 and commercial operation is expected in late 1995 or
early 1996. The estimated price of the Cope plant, excluding financing
costs and AFC but including an allowance for escalation, is $450 million.
In addition, the transmission lines for interconnection with the Company's
system are expected to cost $26 million.
48
Under the Duke/Fluor Daniel contract the Company must make specified
monthly minimum payments. These minimum payments do not include amounts for
inflation on a portion of the contract which is subject to escalation
(approximately 34% of the total contract amount). The aggregate amount of
such required minimum payments remaining at December 31, 1993 is as follows
(in thousands):
1994 $168,152
1995 59,766
1996 5,603
Total $233,521
Through December 31, 1993 the Company paid $142.0 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 $9.4
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 not exceed approxi-
mately $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 $1.4 billion for any losses in excess of $500 million pursuant
to existing primary coverages (with ANI) on 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 by NEIL.
Based on the current annual premium, this retroactive premium would not
exceed approximately $8.1 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and expenses arising
from a nuclear incident at Summer Station exceed the policy limits of
insurance, or to the extent such insurance becomes unavailable in the
future, and to the extent that the Company's rates would not recover the
cost of any purchased replacement power, the Company will retain the risk of
loss as a self-insurer. The Company has no reason to anticipate a serious
nuclear incident at Summer Station. If such an incident were to occur, it
could have a materially adverse impact on the Company's financial position.
C. Litigation
In January 1994 the Company, acting on behalf of itself and the PSA (as
co-owners of Summer Station), reached a settlement with Westinghouse
Electric Corporation (Westinghouse) resolving a dispute involving steam
generators provided by Westinghouse to Summer Station which are defective in
design, workmanship and materials. Terms of the settlement are confidential
by agreement of the parties and order of the court. The Company had filed
an action in May 1990 against Westinghouse in the U. S. District Court
for South Carolina; an order dismissing this suit was issued on
January 12, 1994.
D. Environmental
As described in Note 1L, the Company has an environmental assessment
program to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are initiated an
estimate is made of the amount of expenditures, if any, necessary to
investigate and clean up each site. These estimates are refined as
additional information becomes available; therefore actual expenditures
could significantly differ from the original estimates. Amounts estimated
and accrued to date for site assessments and cleanup relate primarily to
regulated operations; such amounts have been deferred and are being
amortized and recovered through rates over a ten-year period.
49
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1993, 1992 and 1991 and for the
years then ended is as follows:
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
Assets utilized for overall Company operations 495,166
Total assets $3,189,939
50
1992
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 829,938 $160,820 $ 3,623 $ 994,381
Operating expenses,
excluding depreciation
and amortization 572,234 133,611 9,205 715,050
Depreciation and
amortization 87,367 9,534 163 97,064
Total operating expenses 659,601 143,145 9,368 812,114
Operating income (loss) $ 170,337 $ 17,675 $(5,745) 182,267
Add - Other income, net 3,006
Less - Interest charges 83,110
Net income $ 102,163
Capital expenditures:
Identifiable $ 223,697 $ 10,409 $ 346 $ 234,452
Utilized for overall Company operations 8,877
Total $ 243,329
Identifiable assets at
December 31, 1992:
Utility plant, net $2,271,895 $177,309 $ 1,240 $2,450,444
Inventories 68,435 2,967 481 71,883
Total $2,340,330 $180,276 $ 1,721 2,522,327
Assets utilized for overall Company operations 368,626
Total assets $2,890,953
51
1991
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 867,685 $ 150,788 $ 3,869 $1,022,342
Operating expenses,
excluding depreciation
and amortization 596,466 128,529 9,023 734,018
Depreciation and
amortization 82,503 8,969 146 91,618
Total operating expenses 678,969 137,498 9,169 825,636
Operating income (loss) $ 188,716 $ 13,290 $ (5,300) 196,706
Add - Other income, net 3,283
Less - Interest charges 77,153
Net income $ 122,836
Capital expenditures:
Identifiable $ 191,218 $ 16,029 $ 89 $ 207,336
Utilized for overall Company operations 7,967
Total $ 215,303
Identifiable assets at
December 31, 1991:
Utility plant, net $2,154,221 $ 176,570 $ 1,073 $2,331,864
Inventories 69,316 2,553 476 72,345
Total $2,223,537 $ 179,123 $ 1,549 2,404,209
Assets utilized for overall Company operations 344,371
Total assets $2,748,580
52
12. SUPPLEMENTARY INCOME STATEMENT INFORMATION:
Maintenance expense (including repairs) and provision for depreciation
and amortization of utility plant are shown separately in the accompanying
consolidated statements of income, except for amounts charged to clearing
and other accounts, which amounts are not significant. Advertising expenses
are not material and there were no royalties. Taxes other than income taxes
are as follows (amounts for nonutility operations are not significant):
December 31,
1993 1992 1991
(Thousands of Dollars)
State electric generation tax $ 4,056 $ 4,299 $ 3,638
General property taxes 47,624 47,320 44,567
Special state utility license 1,814 1,965 1,595
Federal social security taxes 8,534 8,113 7,463
State gross receipts tax 2,871 3,427 2,734
Other taxes 462 470 942
Total charged to operating expenses $65,361 $65,594 $60,939
13. QUARTERLY FINANCIAL DATA (UNAUDITED):
1993
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $279,241 $244,485 $329,673 $265,034 $1,118,433
Operating income 55,274 38,934 79,363 45,748 219,319
Net Income 36,820 21,327 61,032 26,789 145,968
1992
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $263,576 $222,097 $270,937 $237,771 $994,381
Operating income 49,805 33,452 58,149 40,861 182,267
Net Income 30,055 13,528 36,747 21,833 102,163
53
SCHEDULE V
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Property, Plant and Equipment
Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 2,526,525 $ 387,277 $ $ 2,913,802
Production Plant - Steam 419,861,153 48,342,749 $23,766,610 (58,121) 444,379,171
Production Plant - Nuclear 901,572,157 6,351,974 2,080,492 905,843,639
Production Plant - Hydraulic 252,749,355 1,300,683 57,399 (16,026) 253,976,613
Other Production 63,281,062 866,307 1,500 (899,820) 63,246,049
Transmission 307,889,993 14,609,788 218,883 (642,210) 321,638,688
Distribution 909,829,946 71,365,534 6,417,737 622,432 975,400,175
General 95,416,815 7,591,100 4,188,810 726,828 99,545,933
Construction Work in Progress 203,255,081 116,265,554 319,520,635
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 3,157,318,978 267,080,966 36,731,431 (266,917) 3,387,401,596
Gas Utility Plant:
Intangible Plant 2,002 2,002
Production Plant 12,404,326 124,400 364,632 12,164,094
Distribution 233,452,324 9,334,575 244,443 242,542,456
General 17,816,286 752,470 714,102 (55,270) 17,799,384
Construction Work in Progress 2,154,465 1,462,713 3,617,178
Total Gas Plant 265,829,403 11,674,158 1,325,179 (55,270) 276,123,112
Transit Utility Plant:
Plant in Service 3,286,740 820,846 338,083 3,769,503
Construction Work In Progress 346,440 (217,070) 129,370
Total Transit Plant 3,633,180 603,776 338,083 3,898,873
Common Utility Plant:
Plant in Service 65,124,200 9,842,345 512,645 (1,650,001) 72,803,899
Construction Work in Progress 11,318,260 4,091,970 15,410,230
Total Common Plant 76,442,460 13,934,315 512,645 (1,650,001) 88,214,129
Nuclear Fuel, Net 39,916,340 7,325,982 (18,155,649) 29,086,673
Total Utility Plant 3,543,140,361 300,619,197 38,907,338 (20,127,837) 3,784,724,383
Nonutility Property 13,360,800 249,267 16,729 6,403 13,599,741
Total Property, Plant and
Equipment $3,556,501,161 $300,868,464 $38,924,067 $(20,121,434) $3,798,324,124
(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.
54
SCHEDULE V
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Property, Plant and Equipment
Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 1,745,368 $ 668,802 $ 112,355 $ 2,526,525
Production Plant - Steam 386,509,775 39,281,836 $ 6,311,184 380,726 419,861,153
Production Plant - Nuclear 902,210,500 10,513,580 11,089,182 (62,741) 901,572,157
Production Plant - Hydraulic 252,263,540 729,289 11,087 (232,387) 252,749,355
Other Production 60,580,141 3,495,438 72,541 (721,976) 63,281,062
Transmission 284,885,248 23,378,760 345,830 (28,185) 307,889,993
Distribution 836,231,555 80,261,671 6,726,789 63,509 909,829,946
General 86,645,581 12,212,253 2,218,502 (1,222,517) 95,416,815
Construction Work in Progress 171,497,768 31,757,313 203,255,081
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 2,983,506,367 202,298,942 26,775,115 (1,711,216) 3,157,318,978
Gas Utility Plant:
Intangible Plant 2,002 2,002
Production Plant 11,729,301 677,519 (2,494) 12,404,326
Distribution 222,086,762 12,319,371 953,809 233,452,324
General 17,254,519 832,364 455,798 185,201 17,816,286
Construction Work in Progress 5,574,900 (3,420,435) 2,154,465
Total Gas Plant 256,647,484 10,408,819 1,409,607 182,707 265,829,403
Transit Utility Plant:
Plant in Service 3,626,110 25,203 364,573 3,286,740
Construction Work In Progress 25,422 321,018 346,440
Total Transit Plant 3,651,532 346,221 364,573 3,633,180
Common Utility Plant:
Plant in Service 59,209,415 6,427,058 564,596 52,323 65,124,200
Construction Work in Progress 8,868,396 2,449,864 11,318,260
Total Common Plant 68,077,811 8,876,922 564,596 52,323 76,442,460
Nuclear Fuel, Net 41,708,502 21,398,027 (23,190,189) 39,916,340
Total Utility Plant 3,353,591,696 243,328,931 29,113,891 (24,666,375) 3,543,140,361
Nonutility Property 13,337,632 222,651 18,235 (181,248) 13,360,800
Total Property, Plant and
Equipment $3,366,929,328 $243,551,582 $29,132,126 $(24,847,623) $3,556,501,161
(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.
55
SCHEDULE V
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Property, Plant and Equipment
Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 1,498,215 $ 247,153 $ 1,745,368
Production Plant - Steam 375,757,013 11,221,353 $ 2,107,137 $ 1,638,546 386,509,775
Production Plant - Nuclear 892,803,058 11,400,155 1,990,340 (2,373) 902,210,500
Production Plant - Hydraulic 246,061,917 6,234,421 18,421 (14,377) 252,263,540
Other Production 24,719,968 36,664,254 151,891 (652,190) 60,580,141
Transmission 268,810,887 17,218,465 756,709 (387,395) 284,885,248
Distribution 767,262,239 75,701,545 6,388,466 (343,763) 836,231,555
General 78,793,633 10,608,299 2,751,716 (4,635) 86,645,581
Construction Work in Progress 166,273,512 5,224,256 171,497,768
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 2,822,917,333 174,519,901 14,164,680 233,813 2,983,506,367
Gas Utility Plant:
Intangible Plant 2,002 2,002
Production Plant 12,165,685 132,278 568,662 11,729,301
Distribution 207,249,333 15,419,520 582,091 222,086,762
General 16,549,092 2,010,529 1,308,383 3,281 17,254,519
Construction Work in Progress 7,108,395 (1,533,495) 5,574,900
Total Gas Plant 243,074,507 16,028,832 2,459,136 3,281 256,647,484
Transit Utility Plant:
Plant in Service 3,834,731 109,676 318,297 3,626,110
Construction Work In Progress 45,951 (20,529) 25,422
Total Transit Plant 3,880,682 89,147 318,297 3,651,532
Common Utility Plant:
Plant in Service 53,402,648 7,485,224 463,637 (1,214,820) 59,209,415
Construction Work in Progress 5,522,233 3,346,163 8,868,396
Total Common Plant 58,924,881 10,831,387 463,637 (1,214,820) 68,077,811
Nuclear Fuel, Net 43,394,098 16,697,735 (18,383,331) 41,708,502
Total Utility Plant 3,172,191,501 218,167,002 17,405,750 (19,361,057) 3,353,591,696
Nonutility Property 15,002,658 632,077 496,481 (1,800,622) 13,337,632
Total Property, Plant and
Equipment $3,187,194,159 $218,799,079 $17,902,231 $(21,161,679) $3,366,929,328
(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.
56
SCHEDULE VI
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 510,230 $ 215,400 $ 725,630
Production Plant - Steam 183,320,992 11,748,848 $26,118,661 168,951,179
Production Plant - Nuclear 258,546,891 27,136,078 4,336,461 281,346,508
Production Plant - Hydraulic 56,833,113 3,708,900 387,290 60,154,723
Other Production 20,965,067 1,992,545 48,970 22,908,642
Transmission 94,236,791 7,748,900 610,744 101,374,947
Distribution 274,166,096 29,477,600 7,264,838 296,378,858
General 35,824,269 6,112,419 3,690,790 38,245,898
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 925,340,340 88,140,690 42,457,754 971,023,276
Gas Utility Plant:
Production Plant 4,051,584 344,400 118,173 4,277,811
Distribution 78,240,161 8,798,400 353,335 86,685,226
General 6,229,475 939,849 473,341 6,695,983
Total Gas Plant 88,521,220 10,082,649 944,849 97,659,020
Transit Utility Plant 2,393,120 167,000 333,808 2,226,312
Common Utility Plant:
Common Plant 21,919,678 2,711,444 395,972 24,235,150
Intangible Plant 1,764,900 622,600 2,387,500
Total Common Plant 23,684,578 3,334,044 395,972 26,622,650
Total Utility Plant 1,039,939,258 101,724,383 44,132,383 1,097,531,258
Nonutility Property 818,636 150,000 16,729 951,907
Total Property, Plant and
Equipment $1,040,757,894 $101,874,383 $ 44,149,112 $1,098,483,165
(*) After deduction of net salvage.
57
SCHEDULE VI
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 483,330 $ 26,900 $ 510,230
Production Plant - Steam 181,467,097 9,327,525 $ 7,473,630 183,320,992
Production Plant - Nuclear 244,349,995 26,159,978 11,963,082 258,546,891
Production Plant - Hydraulic 53,551,159 3,474,075 192,121 56,833,113
Other Production 18,442,317 2,636,400 113,650 20,965,067
Transmission 87,812,534 7,068,000 643,743 94,236,791
Distribution 251,465,003 28,531,200 5,830,107 274,166,096
General 32,484,258 5,140,301 1,800,290 35,824,269
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 870,992,584 82,364,379 28,016,623 925,340,340
Gas Utility Plant:
Production Plant 3,722,784 328,800 4,051,584
Distribution 70,865,818 8,373,600 999,257 78,240,161
General 5,489,388 976,408 236,321 6,229,475
Total Gas Plant 80,077,990 9,678,808 1,235,578 88,521,220
Transit Utility Plant 2,579,278 146,500 332,658 2,393,120
Common Utility Plant:
Common Plant 18,020,122 4,033,463 133,907 21,919,678
Intangible Plant 1,160,900 604,000 1,764,900
Total Common Plant 19,181,022 4,637,463 133,907 23,684,578
Total Utility Plant 972,830,874 96,827,150 29,718,766 1,039,939,258
Nonutility Property 366,216 148,100 (304,320) 818,636
Total Property, Plant and
Equipment $973,197,090 $ 96,975,250 $ 29,414,446 $1,040,757,894
(*) After deduction of net salvage.
58
SCHEDULE VI
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 282,630 $ 200,700 $ 483,330
Production Plant - Steam 176,597,113 8,986,800 $ 4,116,816 181,467,097
Production Plant - Nuclear 220,460,998 25,905,578 2,016,581 244,349,995
Production Plant - Hydraulic 50,787,917 3,478,800 715,558 53,551,159
Other Production 17,204,322 1,591,396 353,401 18,442,317
Transmission 82,003,719 6,616,800 807,985 87,812,534
Distribution 232,605,806 26,114,400 7,255,203 251,465,003
General 29,725,228 5,114,200 2,355,170 32,484,258
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 810,604,624 78,008,674 17,620,714 870,992,584
Gas Utility Plant:
Production Plant 3,949,910 334,800 561,926 3,722,784
Distribution 63,862,085 7,863,600 859,867 70,865,818
General 5,547,775 981,700 1,040,087 5,489,388
Total Gas Plant 73,359,770 9,180,100 2,461,880 80,077,990
Transit Utility Plant 2,674,599 130,100 225,421 2,579,278
Common Utility Plant:
Common Plant 14,793,032 3,723,000 495,910 18,020,122
Intangible Plant 577,700 583,200 1,160,900
Total Common Plant 15,370,732 4,306,200 495,910 19,181,022
Total Utility Plant 902,009,725 91,625,074 20,803,925 972,830,874
Nonutility Property 635,832 187,000 456,616 366,216
Total Property, Plant and
Equipment $902,645,557 $ 91,812,074 $ 21,260,541 $973,197,090
(*) After deduction of net salvage.
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 29, 1993 to hold
office until the next annual meeting of the Company's stockholder
on April 28, 1994.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 50 Since September 30, 1988, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).
Since January 12, 1988, Chairman and Chief
Executive Officer of Amick Processing, Inc.
and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia, SC.
William B. Bookhart, Jr. 52 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 64 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; The Seibels Bruce Group,
Inc., Columbia, SC.
Hugh M. Chapman 61 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.
60
Name and Year First
Became Director Age Principal Occupation; Directorships
James B. Edwards, D.M.D. 66 President and Professor of Maxillofacial
(1986) Surgery, Medical University of South
Carolina.
U.S. Secretary of Energy from January 1981 to
November 1982.
Governor of South Carolina, 1975-1979.
Director, Phillips Petroleum Co.,
Bartlesville, OK; Brendle's,
Inc., Elkin, NC; Chemical Waste
Management, Inc., Chicago, IL; Imo
Industries, Inc., Lawrenceville, NJ;
South Carolina National Corporation,
Columbia, SC; South Carolina National Bank,
Columbia, SC; National Data Corporation,
Atlanta, GA; Encyclopedia Britannica,
Chicago, IL; Communications Satellite
Corporation;
SCANA Corporation, Columbia, SC.
Elaine T. Freeman 58 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization).
Director, SCANA Corporation, Columbia, SC.
Lawrence M. Gressette, Jr. 62 Since February 1, 1990, Chairman of the
(1987) Board, Chief Executive Officer and
President of SCANA Corporation and
Chairman of the Board and Chief
Executive Officer of all SCANA
subsidiaries, including the Company.
From September 1, 1985 to January 31, 1990,
President of SCANA Corporation.
From January 1, 1988 to February 21, 1989,
President and Treasurer of SCANA
Corporation.
From May 1, 1987 to January 31, 1990, Vice
Chairman of the Company.
Director, Wachovia Corporation, Winston-
Salem, NC; SCANA Corporation, Columbia, SC.
Benjamin A. Hagood 66 Since January 1, 1993, Chairman of the Board,
(1974) William M. Bird and Company, Inc.,
Charleston, SC (wholesale distributor of
floor covering material).
Prior to January 1, 1993, President and
Director, William M. Bird and Company,
Inc., Charleston, SC.
61
Name and Year First
Became Director Age Principal Occupation; Directorships
Benjamin A. Hagood Director, SCANA Corporation, Columbia, SC.
(continued)
W. Hayne Hipp 54 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 51 Since November 12, 1990, President and Chief
(1991) Operating Officer of the Company.
From April 4, 1988 to November 9, 1990,
Senior Vice President-Division Operations,
Pennsylvania Power and Light Company,
Allentown, PA.
Director, SCANA Corporation, Columbia, SC.
F. Creighton McMaster 64 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. 65 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Third National Bank, Nashville,
TN; SCANA Corporation, Columbia, SC.
John B. Rhodes 63 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 47 For more than five years, Senior Vice
(1991) President, Chief Financial Officer and
Controller of SCANA Corporation.
Since August 28, 1991 Chief Financial Officer
of the Company.
Director, SCANA Corporation, Columbia, SC.
62
Name and Year First
Became Director Age Principal Occupation; Directorships
E. Craig Wall, Jr. 56 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; Blue Cross/Blue Shield of
South Carolina, Columbia, SC; SCANA
Corporation, Columbia, SC.
John A. Warren 69 Since February 1, 1990, Chairman of the
(1982) Board Emeritus of SCANA Corporation. Since
April 6, 1989, Chairman of the Board of
Palmetto Seed Capital Corporation,
Columbia, SC (venture capital corporation).
From April 23, 1986 to January 31, 1990,
Chairman of the Board and Chief Executive
Officer of SCANA Corporation and
subsidiaries.
Director, The Liberty Corporation,
Greenville, SC; SCANA Corporation,
Columbia, SC.
63
EXECUTIVE OFFICERS OF THE COMPANY
The executive 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) 62 Chairman of the Board and
Chief Executive Officer 1990-present
Vice Chairman of the Board *-1990
B.D. Kenyon (1) 51 President and Chief
Operating Officer 1990-present
Senior Vice President -
Division Operations,
Pennsylvania Power and
Light Company 1988-1990
W.B. Timmerman (1) 47 Chief Financial Officer 1991-present
Senior Vice President,
Chief Financial Officer
and Controller, SCANA 1988-present
G.J. Bullwinkel, Jr. 45 Senior Vice President-
Fossil & Hydro Production 1993-present
Senior Vice President-
Production 1991-1992
Vice President-Customer
Relations, Southern Division *-1991
R.W. Stedman 52 Senior Vice President-
Administrative Support
Group 1993-present
Senior Vice President-
Administration 1988-1992
*Indicates position held at least since March 1, 1989
(1) Also an executive officer of SCANA
64
Positions Held During
Name Age Past Five Years Dates
J.H. Young, Jr. 57 Senior Vice President-
Customer Relations 1988-present
W.A. Darby 48 Vice President-Gas Operations *-present
P.T. Smith 46 Vice President and General
Counsel - Rates and Regulatory
Affairs 1992-present
Vice President - Regulatory
Affairs 1991-1992
Vice President - Rates,
Purchasing & Regulatory Affairs *-1991
J.E. Addison 33 Vice President and Controller 1992-present
Controller 1991
Partner - Hughes, Boan &
Addison, CPA's 1990-1991
Manager - Deloitte & Touche *-1990
*Indicates position held at least since March 1, 1989
There is no family relationship between any of the persons named in
response to Item 10.
65
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to compensation paid
or accrued by SCANA Corporation and its subsidiaries, including the Company,
during the years 1993, 1992 and 1991 to the Chief Executive Officer of the
Company and to each of the other four most highly compensated executive officers
of the Company during 1993 who were serving as executive officers of the Company
at the end of 1993.
SUMMARY COMPENSATION TABLE
Name and principal position Year Annual Compensation Long-Term All other4
Compensation compensa-
tion ($)
Payouts
Salary Bonus1 Other annual2
($) ($) compensa- LTIP3
tion ($) payouts ($)
(a) (b) (c) (d) (e) (h) (i)
L. M. Gressette, Jr. 1993 383,5575 186,615 57,375 266,007 23,013
Chairman of the Board, 1992 368,426 0 60,488 82,151 22,104
President, Chief Executive 1991 339,904 144,000 61,000
Officer and Director -
SCANA Corporation
and the Company and
Chairman of the Board and
Chief Executive Officer -
all SCANA subsidiaries,
including the Company
B. D. Kenyon 1993 297,760 90,090 4,201 125,792 17,866
President and Chief Operating 1992 291,355 0 3,265 46,250 17,481
Officer 1991 262,925 81,450 0
Director - SCANA Corporation
and the Company
W. B. Timmerman 1993 220,752 95,738 2,828 109,768 13,245
Senior Vice President and 1992 215,817 0 2,303 15,906 12,949
Chief Financial Officer - 1991 187,615 70,950 33,000
SCANA Corporation
Chief Financial Officer
Director - SCANA Corporation
and the Company
J. H. Young 1993 167,566 51,975 1,542 70,508 10,054
Senior Vice President 1992 165,102 0 1,084 23,556 9,906
Customer Relations 1991 144,861 45,450 17,000
R. W. Stedman 1993 170,361 51,975 1,107 70,508 10,222
Senior Vice President - 1992 167,259 0 985 23,556 10,036
Administrative Support Group 1991 146,155 45,450 17,000
1 Payments under the annual Performance Incentive Plan described hereafter.
2 Other annual compensation consists of (i) perquisites for those named individuals
whose perquisites exceeded the lesser of 10% of their salary and bonus or $50,000
and (ii) payments to cover taxes on benefits. The perquisites for Mr. Gressette
includes compensation related to the Whole Life Option described hereafter in the
amount of $50,018 for both 1993 and 1992.
3 Payments under the long term Performance Share Plant described hereafter.
4 All other compensation includes Company contributions to the SCANA Stock Purchase
Savings Plan ("Savings Plan") and the Supplementary Voluntary Deferral Plan
described hereafter based on the funding formula for all employees of the
Company.
5 Reflects actual salary paid in 1993. Base salary of $395,000 became effective in
May of 1993; the 1992 salary of $360,000 was in effect from January to April of
1993.
66
DESCRIPTION OF PLANS
Incentive Compensation
To bring total compensation of officers to market levels,
the Company has two incentive plans:
Annual Performance Incentive Plan
SCANA has annual Performance Incentive Plans for officers of
SCANA and its subsidiaries. The plans promote SCANA's
pay-for-performance philosophy, as well as its goal of
having a meaningful amount of executive pay "at-risk."
Through these plans, financial incentives are provided in
the form of annual cash bonuses that are paid only when
corporate, business unit and individual goals are
achieved.
Short-term incentive awards are targeted below the median of
the market. Executives eligible for these plans are
assigned threshold, target and maximum bonus levels as a
percentage of salary level. Bonuses earned are based on
the level of the preestablished goals achieved. Award
payouts may increase to a maximum of 1.5 times target, if
Company performance exceeds the goals established. Even
if this were to occur, payouts would still be below the
market median. Award payouts may decrease, generally to a
minimum of one-half the target-level awards, if the
Company's performance is below targeted goals. Awards
earned based on the achievement of preestablished goals
may nonetheless be decreased to zero (as was done in
1992), if the Management Development and Corporate
Performance Committee (Performance Committee) in its
discretion determines that actual results do not warrant
the levels of payouts otherwise earned.
The various plans in which officers of SCANA and its
subsidiaries participate focus generally on short-term
goals affecting profitability, efficiency, quality of
service, customer satisfaction and progress toward SCANA's
strategic objectives for the Company and its other
subsidiaries. New performance categories for officers in
the various plans are established annually. Specific
performance measures, and their weights, also vary from
year to year.
For 1993, the specific measures in each plan, and their
weights, for the officers included in the Summary
Compensation Table on page 66 are described below. The
relationship of performance to payouts for the officers in
each plan also is discussed.
For officers of SCANA, 80% of the total award is based
on corporate Earnings Per Share ("EPS") goals. The
remaining 20% is tied to the achievement of
individual performance goals, and is awarded on a
discretionary basis.
Specific EPS goals are established that correspond
to threshold, target and maximum payouts for the
EPS portion of awards. For 1993, SCANA's EPS
results were sufficient to result in maximum
payouts for that portion of the awards. Individual
performance for corporate officers also was
determined to be sufficient to result in maximum
-level payouts for that portion of the awards.
Awards for officers of the Company are based on
three performance categories: corporate EPS,
numerous corporate and Strategic Business Unit
(SBU) financial and productivity goals, and
additional SBU strategic initiatives (i.e.,
activities that focus on improvements in existing
operating procedures, quality of service and
product, human resources matters, etc.). One-third
of the total award is based on results in each
performance category. Threshold, target and
maximum performance levels are established for each
category; payouts will vary based on the actual
level of performance achieved.
For 1993, the overall Company performance in all
three categories was such that payouts exceeded
target-level awards, but were less than the maximum
awards possible. Although results for the first
two performance categories were above target
performance levels, results in the strategic
initiative category were below that level.
Long-Term Performance Share Plan
SCANA has a long-term Performance Share Plan for officers of
SCANA and its subsidiaries. The long-term Performance
Share Plan measures SCANA's Total Shareholder Return
("TSR") relative to a group of peer companies (PSP Peer
Group) over a three-year period. The PSP Peer Group
includes 97 electric and gas utilities, none of which have
annual revenues of less than $100 million.
Total Shareholder Return 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 a large group of other
utilities reflects SCANA's recognition that investors
could have invested their funds in other utility
companies. Comparing SCANA's TSR against the TSR of the
PSP Peer Group 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 based
primarily on their salary level. In determining award
sizes, levels of responsibilities and competitive
practices also are considered. Target awards are
established at levels slightly below the median of the
market and represent a significant portion of executives
"at-risk" compensation. But, 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
outstanding. 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 target payouts 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. 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 cash or a combination of the two.
For the three-year period from 1991 through 1993, SCANA's
TSR was at the 79th percentile of the PSP Peer Group.
This resulted in payouts in February 1994 at the maximum
level possible.
The combination of the annual Incentive Plan and the
Performance Share Plan provides an opportunity to bring a
participant's compensation to market levels. The progressive
payout formulas in both plans dictate that above-market pay can
be earned only for better-than-average corporate financial
performance, and that poor performance will result in below-
market pay.
68
The following table shows the target awards made in 1993 for
potential payment in 1996 under the long-term Performance Share
Plan, and estimated future payouts under that plan at threshold,
target and maximum levels.
LONG-TERM INCENTIVE PLAN
TARGET AWARDS FOR 1993 TO BE PAID IN 1996
Estimated Future Payouts Under Non-Stock Price-
Based Plans
Number of Performance or
Shares, Units Other Period Threshold Target Maximum
Name or Other Rights Until Maturation ($) or (#) ($ or #) ($ or #)
(#) or Payout
(a) (b) (c) (d) (e) (f)
L. M. Gressette, Jr. 4,100 1993 - 1995 1,640 4,100 6,150
B. D. Kenyon 1,810 1993 - 1995 724 1,810 2,715
W. B. Timmerman 1,580 1993 - 1995 632 1,580 2,370
J. H. Young 950 1993 - 1995 380 950 1,425
R. W. Stedman 950 1993 - 1995 380 950 1,425
Defined Contribution Plans
Under the Savings Plan, most of the Company's employees may
contribute up to 15% of their eligible earnings. The Company
matches each employee's contribution on a dollar-for-dollar basis
up to a maximum of 6% of the participant's eligible earnings as
limited by the Internal Revenue Code (IRC). Both Company and
employee contributions are invested in SCANA's Common Stock.
In addition to the Savings Plan, SCANA has a Supplementary
Voluntary Deferral Plan (the "Supplementary Plan") for certain
highly compensated employees of the Company and other SCANA
subsidiaries. The Supplementary Plan is designed to provide
employees whose participation in the Savings Plan is limited by
the IRC with the ability to contribute and receive matching
contributions in the same percentage as employees generally.
However, unlike the Savings Plan where actual shares of SCANA
Common Stock are acquired, under the Supplementary Plan the
deferred amounts and matches are only accounted for as though
shares of common stock had been purchased.
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 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. 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, 1994 and
are not subject to any deduction for Social Security or other
offset amounts.
69
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$125,000 35,130 46,840 58,550 70,260 72,595
150,000 42,630 56,840 71,050 85,260 88,220
175,000 50,130 66,840 83,550 100,260 103,845
200,000 57,630 76,840 96,050 115,260 119,470
225,000 65,130 86,840 108,550 130,260 135,095
250,000 72,630 96,840 121,050 145,260 150,720
300,000 87,630 116,840 146,050 175,260 181,970
350,000 102,630 136,840 171,050 205,260 213,220
400,000 117,630 156,840 196,050 235,260 244,470
450,000 132,630 176,840 221,050 265,260 275,720
500,000 147,630 196,840 246,050 295,260 306,970
The compensation shown in Column (c) of the Summary
Compensation Table for the individuals named therein is covered
by the Retirement Plan and/or a SERP. Messrs. Gressette, Kenyon,
Timmerman, Young and Stedman now have credited service under the
Retirement Plan (or its equivalent under the SERP) of 31, 20, 15,
31 and 21 years, respectively.
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
the Company will pay to each participant for 180 months, upon
retirement at or after age 65, a monthly retirement benefit 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 Key Employee
Retention 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 -
$106,863; Mr. Kenyon - $126,347; Mr. Timmerman - $105,411; Mr.
Young - $56,013; and Mr. Stedman - $66,729.
Life Insurance Plans
The Company offers its officers and certain other highly-
compensated employees an option to choose whole life insurance
(the "Whole Life Option") in lieu of the term life insurance
provided employees generally. Under this plan, the employee
becomes the owner of a policy with a death benefit of between
$200,000 and $550,000 depending upon the salary grade of the
employee.
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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
obligated 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
There are no executive officer-director interlocks where an
executive officer of the Company serves on the compensation
committee of another company that has an executive officer
serving on the Company's Board of Directors. Messrs. Hipp,
McMaster, Rhodes and Warren are all members of the Long-Term
Compensation Committee which administers the Performance Share
Plan. Messrs. Hipp and Rhodes also are members of the
Performance Committee which generally handles all other executive
compensation matters. Mr. Warren was the Chief Executive Officer
of the Company from April 23, 1986 until January 31, 1990.
Information with respect to transactions with entities with which
Messrs. Hipp, McMaster, Rhodes and Warren are connected are
described below. Mr. Gressette, Chairman of the Board and Chief
Executive Officer of the Company, is an ex-officio (i.e.
nonvoting) member of the Performance Committee. The Performance
Committee receives his input on compensation matters concerning
executive compensation of other officers but the committee
deliberates and makes its decisions without his participation.
Mr. Rhodes is the Chairman and Chief Executive Officer of
Rhodes Oil Company, Inc. Purchases from Rhodes Oil Company, Inc.
totaling $62,500 for fuel oil and gasoline were made during 1993
by the Company. It is anticipated that such purchases will
continue in the future.
Mr. McMaster is the President and Manager of Winnsboro
Petroleum Company. Purchases from Winnsboro Petroleum Company
totaling $77,549 for fuel oil and gasoline were made during 1993
by the Company. It is anticipated that such purchases will
continue in the future.
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Mr. Hipp, is the President and Chief Executive Officer of
The Liberty Corporation. Mr. Hipp and John A. Warren are
Directors of The Liberty Corporation. During 1993 certain of the
insurance policies purchased by the Company on the lives of
employees were written by Liberty Life Insurance Company, a
subsidiary of the Liberty Corporation, and it is expected that
this relationship will continue in the future. The total amount
paid during 1993 by the Company to Liberty Life Insurance Company
was $538,905.
COMPENSATION OF DIRECTORS
Fees
All of the Directors of the Company are also Directors of
SCANA. During 1993, directors who are not employees of SCANA or
its subsidiaries were each paid $14,500 for services rendered,
plus $1,500 for each Board meeting attended and $700 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 $150. The fee for attendance
at a conference is $500. 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 SCANA or its subsidiaries receive
no compensation for serving as directors or attending meetings.
Deferral Plan
The Company 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 1993 and currently, the
rate is set at the announced prime rate of The South Carolina
National Bank. During 1993, the only director participating in
the plan was Mr. Rhodes. Interest credited to Mr. Rhodes'
deferral account during 1993 was $8,526.
Endowment Plan
Each director participates 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 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 and 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.
72
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 as of March 10, 1994,
the shares of SCANA's Common Stock beneficially owned by each
continuing director and nominee, each of the executive officers
named in the Summary Compensation Table on page 66, and the
directors and 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 1,243 W. H. Hipp 1,400
W. B. Bookhart, Jr. 6,884 B. D. Kenyon 4,782
W. T. Cassels, Jr. 1,000 F. C. McMaster 10,288
H. M. Chapman 3,127 Henry Ponder 4,806
J. B. Edwards 2,217 J. B. Rhodes 3,434
E. T. Freeman 1,500 W. B. Timmerman 12,889
L. M. Gressette, Jr. 14,649 E. C. Wall, Jr. 7,000
B. A. Hagood 1,140 John A. Warren 50,823
J. H. Young 5,108
R. W. Stedman 6,474
All directors and executive officers as a group (18 persons) TOTAL 138,764
TOTAL PERCENT OF CLASS 0.3%
(1) Includes shares owned by close relatives, the beneficial ownership
of which is disclaimed by the director or nominee, as follows:
Mr. Amick - 240; Mr. Bookhart - 1,913; Mr. Chapman - 127;
Mr. Gressette - 530; Mr. Hagood - 159; Mr. McMaster - 6,365;
Mr. Warren - 7,160.
Includes shares purchased through December 31, 1993, but not
thereafter, by the Trustee under the Savings Plan.
The information set forth above as to the security ownership
has been furnished to the Company by such persons.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related
transactions, see Item 11., "Compensation Committee Interlocks
and Insider Participation."
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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 28.
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.
Reports on Form 8-K
The Company filed a report on Form 8-K on January 13, 1994
in response to Item 5, "Other Events" regarding the settlement
with Westinghouse Electric Corporation of a lawsuit relating to
the steam generators provided to the Company's Summer Station.
74
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 15, 1994
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
and Chief Executive Officer and Director
DATE February 15, 1994
(ii) Principal financial officer:
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Chief Financial Officer
DATE February 15, 1994
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Controller
DATE February 15, 1994
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 15, 1994
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 15, 1994
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 15, 1994
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 15, 1994
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 15, 1994
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BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 15, 1994
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 15, 1994
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 15, 1994
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 15, 1994
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 15, 1994
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 15, 1994
BY (SIGNATURE) s/E. C. Wall, Jr.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 15, 1994
BY (SIGNATURE) s/John A. Warren
(NAME AND TITLE) John A. Warren, Director
DATE February 15, 1994
76