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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, 1994
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
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, 1995 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 .......................................... 17
Item 3. Legal Proceedings ................................... 19
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 19
PART II
Item 5. Market for Registrant's Common Stock
and Related Security Holder Matters ................ 19
Item 6. Selected Financial Data ............................. 20
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ...... 21
Item 8. Financial Statements and Supplementary Data ......... 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 54
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 54
Item 11. Executive Compensation .............................. 59
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 63
Item 13. Certain Relationships and Related Transactions ...... 63
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 63
SIGNATURES ........................................................ 64
3
DEFINITIONS
The following abbreviations used in the text have the meaning set forth below
unless the context requires otherwise:
ABBREVIATION TERM
AFC......................... Allowance for Funds Used During Construction
BTU......................... British Thermal Unit
Circuit Court............... South Carolina Circuit Court
Clean Air Act............... Clean Air Act Amendments of 1990
Company..................... South Carolina Electric & Gas Company
Consumer Advocate........... Consumer Advocate of South Carolina
Dekatherm................... One million BTUs
DHEC........................ South Carolina Department of Health and
Environmental Control
DOE......................... United States Department of Energy
EPA......................... United States Environmental Protection Agency
FERC........................ United States Federal Energy Regulatory
Commission
Fuel Company................ South Carolina Fuel Company, Inc., an
affiliate
GENCO....................... South Carolina Generating Company, Inc., an
affiliate
KVA......................... Kilovolt-ampere
KW.......................... Kilowatt
KWH......................... Kilowatt-hour
LNG......................... Liquefied Natural Gas
MCF......................... Thousand Cubic Feet
MW.......................... Megawatt
NEPA........................ National Energy Policy Act of 1992
NRC......................... United States Nuclear Regulatory Commission
Peoples..................... Peoples Natural Gas Company of South Carolina
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 Pipeline Corporation
USEC........................ United States Enrichment Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams coal-fired, electric
generating station owned by GENCO
4
PART I
ITEM 1. BUSINESS
THE COMPANY
Organization
The Company, a wholly owned subsidiary of SCANA, is a South
Carolina corporation organized in 1924 and has its principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Company had 4,009
full-time, permanent employees as of December 31, 1994 as compared
to 4,166 full-time, permanent employees as of December 31, 1993.
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 20,000 square miles. The total
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, 1994, 1993 and 1992 is contained in Note 11 of
Notes to Consolidated Financial Statements and all such information
is incorporated herein by reference.
Competition
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulatory
protection. The transition began with the enactment of the Public
Utility Regulatory Policies Act of 1978 which facilitated the entry
of competitors into the electric generation business.
Subsequently, NEPA was enacted in 1992 to promote competition among
utility and nonutility generators in the wholesale electric
generation market. Recent initiatives in some states to lessen
regulation and promote competition, particularly with regard to
retail transmission access, also have accelerated the utility
industry's transition.
Future deregulation of electric wholesale and retail markets
will create opportunities to compete for new and existing customers
and markets. As a result, profit margins and asset values of some
utilities could be adversely affected.
The pace of deregulation, the future market price of
electricity, and the regulatory actions which may be taken by the
PSC in response to the changing environment cannot be predicted.
However, the Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company
reorganized its operations around Strategic Business Units.
Maintaining a competitive cost structure is of paramount importance
in the utility's strategic plan. The Company has undertaken a
variety of initiatives, including reductions in operation and
maintenance costs and in staffing levels. The Company believes
that these actions as well as numerous others that have been and
will be taken demonstrate its ability and commitment to succeed in
the new operating environment to come.
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 1995 the
Company is expected to meet its capital requirements principally
through internally generated funds (approximately 29% 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 customer growth
and 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. On June 7,
1993 the PSC issued an order granting the Company a 7.4% annual
increase in retail electric rates which was 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 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 1995 and the four-year period
1996-1999 as now scheduled, are as follows:
Type of Facilities 1996-1999 1995
(Thousands of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $ 388,193 $129,825
Transmission. . . . . . . . . . . . . . . 92,701 25,928
Distribution. . . . . . . . . . . . . . . 295,571 67,283
Other . . . . . . . . . . . . . . . . . . 69,322 16,874
Nuclear Fuel. . . . . . . . . . . . . . . . 68,171 23,084
Gas . . . . . . . . . . . . . . . . . . . . 60,415 18,895
Transit . . . . . . . . . . . . . . . . . . 1,012 432
Common. . . . . . . . . . . . . . . . . . . 35,090 25,342
Nonutility . . . . . . . . . . . . . . . . 580 175
Total . . . . . . . . . . . . . . $1,011,055 $307,838
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program for
the periods 1995 and 1996-1999, 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 and is
expected to be complete in late 1995 with commercial operation
beginning in early 1996. The estimated cost 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 completion of the new plant, the Company is
contracting for additional power as necessary to ensure that the
energy demands of its customers can be met.
The steam generators at Summer Station were replaced in late
1994 during the regularly scheduled refueling outage. The
replacement was completed in 38 days, a new U. S. record and only
one day off the world record for a steam generator replacement.
The new steam generators are expected to result in shorter, less
costly refueling outages, and greater electricity output is
expected to result from less required maintenance.
During 1994 the Company expended approximately $8.0 million as
part of a program to extend the operating lives of certain
generating facilities. Additional improvements under the program
to be made during 1995 are estimated to cost approximately $9.7
million.
6
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 are at least twice the
annual interest requirements on all Class A Bonds to be outstanding
(Bond Ratio). For the year ended December 31, 1994 the Bond Ratio
was 3.52. 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 $499.8 million at December 31, 1994), Class A Bonds
issued on the basis of retirements of Class A Bonds (no retirement
credits remained at December 31, 1994), 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 $57 million were available
for such purpose as of December 31, 1994), 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, 1994 the New Bond Ratio was 4.85.
The following additional financing transactions have occurred
since December 31, 1993:
On July 21, 1994, the Company issued $100 million of First
Mortgage Bonds, 7.70% series due July 15, 2004 to repay short-
term borrowings in a like amount.
On November 3, 1994 the Company issued $30 million of
Pollution Control Facilities Revenue Bonds due November 1,
2024. The proceeds from the sale of the bonds are being used
to defray the cost of constructing certain facilities for the
disposal of solid waste at the Company's Cope Generating
Station under construction in Orangeburg County, South
Carolina.
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 debt. 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, 1997.
The Company had $265.0 million authorized and unused lines of
credit at December 31, 1994. In addition, the Company has a
credit agreement for a maximum of $75 million to finance nuclear
and fossil fuel inventories with $24.4 million available at
December 31, 1994. Fuel Company has issued a promissory note
due March 31, 1995 to SCANA for the purchase of $19.4 million of
sulfur dioxide emission allowances, including $0.6 million in AFC.
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 are at least one and one-half times the aggregate of all
interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1994
the Preferred Stock Ratio was 2.29.
The ratio of earnings to fixed charges (SEC Method) was 3.46,
3.57, 2.73, 3.32 and 3.33 for the years ended December 31, 1994,
1993, 1992, 1991 and 1990, respectively.
Additional Capital Requirements
In addition to the Company's capital requirements for 1995
described above, approximately $20.7 million will be required for
refunding and retiring outstanding securities and obligations. For
the years 1996-1999, the Company has an aggregate of $162.9 million
of long-term debt maturing (including approximately $59.4 million
for sinking fund requirements, of which $59.0 million may be
satisfied by deposit and cancellation of bonds issued upon the
basis of property additions or bond retirement credits) and $9.8
million of purchase or sinking fund requirements for preferred
stock.
7
Actual 1995 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.
The Company expects that it has or can obtain adequate sources
of financing to meet its projected cash requirements.
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, 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. Fuel
Company's Commercial Paper and amounts outstanding under the
revolving credit agreement, if any, are 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, 1994 Commercial Paper outstanding for nuclear
and fossil fuel inventories was approximately $50.6 million at a
weighted average interest rate of 6.06%. Such fuel inventories
and fuel-related assets and liabilities are included in the
Company's financial statements. (See Notes 1M and 4 of Notes to
Consolidated Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 1994 residential sales of electricity accounted for 42% of
electric sales revenues; commercial sales 30%; industrial sales
21%; sales for resale 4%; and all other 3%. KWH sales by
classification for the years ended December 31, 1994 and 1993 are
presented below:
Sales
KWH %
Classification 1994 1993 Change
(thousands)
Residential 5,311,139 5,650,759 (6.01)
Commercial 4,848,620 4,844,422 0.09
Industrial 5,161,717 4,887,250 5.62
Sale for resale 1,024,376 1,005,968 1.83
Other 494,030 500,937 (1.38)
Total Territorial 16,839,882 16,889,336 (0.29)
Interchange 171,046 198,059 (13.64)
Total 17,010,928 17,087,395 (0.45)
The Company furnishes electricity for resale to three
municipalities, three investor-owned utilities, three electric
cooperatives and one public power authority. Such sales for resale
accounted for 4% of total electric sales revenues in 1994.
During 1994 the Company recorded a net increase of 7,538
electric customers, increasing its total customers to 476,438.
The electric sales volume decreased for the year ended
December 31, 1994 compared to the corresponding period as a result
of decreased residential kilowatt-hour sales and interchange power
delivered due to unusually mild weather in 1994. The peak demand
of 3,444 MW was recorded on January 19, 1994. The all-time record
of 3,557 MW was set on July 29, 1993.
8
Electric Interconnections
The Company purchases all of the electric generation of
Williams Station, owned by GENCO, under a Unit Power Sales
Agreement which has been approved by the FERC. Williams Station
has a generating capacity of 560 MW.
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
1992-1994.
1994 1993 1992
Nuclear:
Per million BTU $ .51 $ .47 $ .52
Coal:
Company:
Per ton $39.92 $39.95 $40.00
Per million BTU 1.57 1.55 1.56
GENCO:
Per ton $41.85 $41.64 $41.82
Per million BTU 1.63 1.62 1.63
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.39 $ 1.33 $ 1.27
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 1992-1994 and the estimates for
1995 and 1996.
Percent of Total KWH Generated
Actual Estimated
1994 1993 1992 1996 1995
Coal 77% 72% 65% 72% 69%
Nuclear 17 22 29 23 26
Hydro 6 5 5 5 5
Natural Gas & Oil - 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, 1994
the Company had approximately a 74-day supply of coal in inventory
and GENCO had approximately a 68-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 1995
(approximately 5.1 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 Initial Final
No. of Tons % of 1995 Sulfur Content Expiration Expiration
Per Year Requirement per Contract Date (1) Date (1)
482,500 9.5 1.1-1.5 02/28/1996 02/29/2000
359,500 7.0 1.0-1.8 12/31/1996 12/31/2002
562,500 11.0 1.1-2.0 03/31/1997 03/31/2003
144,000 2.8 1.1-1.6 04/30/1995 04/30/1997
981,000 19.2 up to 1.5 12/31/1996 12/31/2002
732,170 14.4 0.75-1.75 04/30/1997 04/30/2003
425,000 8.3 0.8-1.5 06/30/1995 06/30/1999
3,686,670 72.2
(1) Contract extensions beyond the initial expiration date are
subject to mutual agreement on price, terms, quantity and
quality.
All of the above contracts, except the contracts expiring on
April 30, 1995 and June 30, 1995 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 1994 had an average sulfur content
of 1.26%, 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 at the State level. However, the Company will be
required to meet the more stringent Federal emissions standards
established by the Clean Air Act (see "Environmental Matters").
The Company currently has adequate supplies of uranium under
contract to manufacture nuclear fuel for Summer Station through
1997. The following table summarizes all contract commitments for
the stages of nuclear fuel assemblies:
Commitment Contractor Regions(1) Term
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 USEC (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.
11 was loaded in 1994 and Region no. 12 will be loaded in
1996.
(2) The contract with the USEC is a "requirements" type contract
whereby the USEC 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 1994 residential sales accounted for 49% of gas sales
revenues; commercial sales 33%; industrial sales 18%. Dekatherm
sales by classification for the years ended December 31, 1994 and
1993 are presented below:
Sales
Dekatherms %
Classification 1994 1993 Change
Residential 11,531,558 12,009,444 (4.0)
Commercial 9,813,454 8,842,728 11.0
Industrial 10,938,713 5,881,309 86.0
Transportation gas 5,469,728 6,993,817 (21.8)
Total 37,753,453 33,727,298 12.0
During 1994 the Company recorded a net increase of 17,155 gas
customers including 13,280 customers of Peoples which were combined
with the Company in 1994. The total customer count increased to
238,433.
The Company purchases all of its natural gas from Pipeline
Corporation.
The demand for gas is affected by conservation, the weather,
the price relationship between gas and alternate fuels and other
factors.
The deregulation of natural gas prices at the wellhead 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 November 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which deregulated the markets for interstate sales of
natural gas by requiring that pipelines provide transportation
services that are equal in quality for all gas supplies whether the
customer purchases gas from the pipeline or another supplier. The
impact of this order on the Company will be primarily through
changes affecting its supplier, Pipeline Corporation.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for 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
magnitude of this new market.
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts
with producers and marketers on a short-term basis at current price
indices and on a long-term basis for reliability assurance at index
prices plus a gas inventory charge. The gas is brought to South
Carolina through transportation agreements with both Southern
Natural and Transco. 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 188,000
Transco Firm Transportation 29,300
Total 217,300
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 $4.29 in 1994 compared to
$3.97 in 1993.
To meet the requirements of the Company and its other high
priority natural gas customers during periods of maximum demand,
Pipeline Corporation supplements its supplies of natural gas from
two LNG plants. The LNG plants are capable of storing the lique-
fied equivalent of 1,900,000 MCF of natural gas, of which
approximately 1,524,833 MCF were in storage at December 31, 1994.
On peak days the LNG plants can regasify up to 150,000 MCF per day.
Additionally, Pipeline Corporation had contracted for 6,450,727 MCF
of natural gas storage space on December 31, 1994, of which
4,550,847 MCF were in storage at such date.
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 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.
12
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 debt. 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, 1997.
The Company holds licenses under the Federal Water Power Act
or the Federal Power Act with respect to all its hydroelectric
projects. The expiration dates of the licenses covering the
projects are as follows:
Project Capability (KW) License Expiration Date
Neal Shoals 5,000 1993
Stevens Creek 9,000 1993
Columbia 10,000 2000
Saluda 206,000 2007
Parr Shoals 14,000 2020
Fairfield Pumped Storage 512,000 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 with the FERC on December 30, 1991. No
competing applications were filed. The Neal Shoals license
application was declared to be ready for environmental analysis by
FERC Notice dated June 3, 1994, and the Stevens Creek Application
was declared to be ready by FERC Notice dated September 6, 1994.
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 is in the process of
performing a Multiple-project Environmental Assessment for Neal
Shoals and a Single-project Environmental Assessment 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. For the sixth consecutive time, the NRC named Summer
Station to its short list of top performing plants.
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 1990-1994 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 12/07/92 $ 72.0* 11.4% 06/07/93 $60.5 84%
Retail 01/03/89 $ 27.2 3.7% 07/03/89 $18.2** 67%**
Transit
Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
* As modified to reflect lowering of rate of return the Company was
seeking.
**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.
On October 27, 1994 the PSC issued an order approving the Company's
request to recover through a billing surcharge to its gas customers the
costs of environmental cleanup at the sites of former manufactured gas
plants. The billing surcharge, which was effective with the first
billing cycle in November 1994 and is subject to annual review, provides
for the recovery of approximately $16.2 million representing
substantially all site assessment and cleanup costs for the Company's
gas operations that had previously been deferred.
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 were 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.
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.
Effective with the first billing cycle in December 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 is subject to an annual review by the
PSC. The PSC order was based on a return on common equity of 12.25%.
On August 26, 1994 the PSC ordered that the WNA be made permanent.
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
nonappealable 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. On April 30, 1994 the PSC issued an order
regarding Pipeline Corporation's recovery of take-or-pay cost incurred
pursuant to FERC-approved settlements with its upstream interstate
pipeline suppliers. This order provided a mechanism for Pipeline
Corporation to recover its take-or-pay cost volumetrically over a period
of approximately 30 months. The Company receives a credit for payments
made prior to the April 30 order which is netted against the current
volumetric surcharge. That net cost is recovered by the Company through
its purchased gas adjustment clause.
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 nonmaterial 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.
Fuel Cost Recovery Procedures
The PSC has established a fuel cost recovery procedure which
determines the fuel component in the Company's retail electric base
rates 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 1994 semiannual review of the fuel cost component of
electric rates, the PSC voted to increase the rate from 13.0 mills per
KWH to 14.16 mills per KWH, a monthly increase of $1.16 for an average
customer using 1,000 KWH a month. For the October 1994 review the PSC
voted to continue the rate of 14.16 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 1994 review the PSC authorized an increase in the
base cost of gas from 47.100 cents per therm to 51.058 cents per therm
which resulted in a monthly increase of $3.96 (including applicable
taxes) based on an average of 100 therms per month on a residential bill
during the heating season.
ENVIRONMENTAL 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. 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 1992 through 1994, capital expenditures for
environmental control amounted to approximately $101.2 million. In
addition, approximately $8.8 million, $7.4 million and $5.7 million of
environmental control expenditures were made during 1994, 1993 and 1992,
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 $36.2 million for 1995 and $169.3 million for the four-
year period 1996 through 1999. These expenditures are included in the
Company's construction program.
15
Air Quality Control
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by the year
2000. These requirements are being phased in over two periods. The
first phase 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. At December 31, 1994, the Company had purchased $19.4
million in emission allowances and had commitments to purchase $6.8
million of emission allowances in 1995. Low nitrogen oxide burners will
be installed to reduce nitrogen oxide emissions.
The Company is continuing to refine a 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 $117 million over the 1995-1999 period
to retrofit existing facilities and an increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2004, the Company anticipates
total capital expenditures of approximately $205 million.
Water Quality Control
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act, compliance
with applicable limitations is achieved under a national permit program.
Discharge permits have been issued for all and renewed for nearly all of
the Company's generating units. Concurrent with renewal of these
permits the permitting agency has implemented more rigorous control
programs. The Company has 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 differ significantly 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
for electric operations and an eight-year period for gas operations.
Such deferred amounts totaled $20.2 million and $19.6 million at
December 31, 1994 and 1993, respectively. Estimates to date include,
among other things, the costs estimated to be associated with the
matters discussed in the following paragraphs.
The Company owns five decommissioned manufactured gas plant sites
which contain residues of by-product chemicals. The Company has
maintained an active review of the sites to monitor the nature and
extent of the residual contamination.
16
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
which may have migrated to the City's aquarium site. In 1994 the City
of Charleston notified the Company that it considers the Company to be
responsible for a $43.5 million increase in costs of the aquarium
project attributable to delays resulting from contamination of the
Calhoun Park Area Site. The Company believes that it has meritorious
defenses against this claim and does not expect its resolution to have
a material impact on its financial position or results of operation.
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.
The Arkansas Department of Pollution Control and Ecology (ADPCE)
has identified the Company as a potentially responsible party for clean-
up of PCBs at an abandoned transformer rebuilding plant in Little Rock,
Arkansas. No formal notice from ADPCE has been received concerning this
issue. The Company does not believe that the resolution of this issue
will have a material effect on its results of operations or financial
position.
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 requires that the United
States government make available by 1998 a permanent repository for
high-level radioactive waste and spent nuclear fuel and imposes a fee
of 1.0 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 Act also imposes on utilities
the primary responsibility for storage of their spent nuclear fuel until
the repository is available.
OTHER MATTERS
With regard to the Company's insurance coverage for Summer Station,
reference is made to Note 10B of Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
ITEM 2. PROPERTIES
The Company's bond indentures, securing the First and Refunding
Mortgage Bonds and First Mortgage Bonds issued thereunder, constitute
direct mortgage liens on substantially all of its property.
17
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 (2)
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 (3) 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 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (4) Gas/Oil Parr, SC 1970 60,000
Williams (5) Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000
Hydro
Neal Shoals Carlisle, SC 1905 5,000
Parr Shoals Parr, SC 1914 14,000
Stevens Creek Martinez, GA 1914 9,000
Columbia Columbia, SC 1927 10,000
Saluda Irmo, SC 1930 206,000
Pumped Storage
Fairfield Parr, SC 1978 512,000
Total (6) 3,316,000
(1) Summer rating.
(2) Excludes Cope Electric Generating Station, a 385,000 KW plant
currently under construction and scheduled for commercial
operation in early 1996.
(3) Represents the Company's two-thirds portion of the Summer
Station.
(4) 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.
(5) The two gas turbines at Williams are leased and have a net
capability of 49,000 KW. This lease expires on June 29, 1997.
(6) Excludes Williams Station.
18
The Company owns 445 substations having an aggregate transformer
capacity of 18,885,437 KVA. The transmission system consists of 3,057
miles of lines and the distribution system consists of 15,421 pole
miles of overhead lines and 3,122 trench miles of underground lines.
GAS
Natural Gas
The Company's gas system, including the Peoples system acquired
by SCANA and transferred to the Company on January 1, 1994, consists
of approximately 6,719 miles of three-inch equivalent distribution
pipelines and approximately 11,078 miles of distribution mains and
related service facilities.
Propane
The Company has propane air peak shaving facilities which can
supplement the supply of natural gas by gasifying propane to yield the
equivalent of 102,000 MCF per day of natural gas.
TRANSIT
The Company owns 97 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 1994 and 1993 the Company
paid $115.1 million and $108.6 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, 1994 approximately $13.2 million
of retained earnings were restricted as to payment of cash dividends
on common stock.
19
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1994 1993 1992 1991 1990
STATEMENT OF INCOME DATA (Thousands of Dollars except statistics)
Operating Revenues:
Electric $ 975,526 $ 940,547 $ 829,938 $ 867,685 $ 851,676
Gas 201,746 174,035 160,820 150,788 147,794
Transit 4,002 3,851 3,623 3,869 4,033
Total Operating Revenues 1,181,274 1,118,433 994,381 1,022,342 1,003,503
Operating Expenses:
Fuel used in electric generation
and purchased power 289,481 275,298 242,122 262,756 254,489
Gas purchased for resale 127,846 107,722 95,854 93,179 94,358
Other operation and maintenance 272,145 268,233 260,098 248,601 243,735
Depreciation and amortization 106,952 101,220 97,064 91,618 87,021
Taxes 154,432 146,641 116,976 129,482 125,954
Total Operating Expenses 950,856 899,114 812,114 825,636 805,557
Operating Income 230,418 219,319 182,267 196,706 197,946
Other Income:
Allowance for equity funds used
during construction 7,989 7,496 4,577 2,966 1,308
Other (718) (911) (1,571) 317 (2,267)
Total Other Income 7,271 6,585 3,006 3,283 (959)
Income Before Interest Charges 237,689 225,904 185,273 199,989 196,987
Interest Charges (Credits):
Interest 92,550 85,222 86,994 81,340 79,481
Allowance for borrowed funds used
during construction (6,904) (5,286) (3,884) (4,187) (3,333)
Total Interest Charges, Net 85,646 79,936 83,110 77,153 76,148
Net Income 152,043 145,968 102,163 122,836 120,839
Dividends on Preferred Stock 5,955 6,217 6,474 6,706 6,911
Earnings Available for Common Stock $ 146,088 $ 139,751 $ 95,689 $ 116,130 $ 113,928
BALANCE SHEET DATA
Utility Plant, Net $2,998,132 $2,687,193 $2,503,201 $2,380,761 $2,270,182
Total Assets $3,587,091 $3,189,939 $2,890,953 $2,748,580 $2,625,407
Capitalization:
Common equity $1,133,432 $1,051,334 $ 963,741 $ 840,505 $ 821,373
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 49,528 52,840 56,154 59,469 62,704
Long-term debt
(excludes current portion) 1,219,991 1,097,043 945,964 993,674 779,524
Total Capitalization $2,428,978 $2,227,244 $1,991,886 $1,919,675 $1,689,628
OTHER STATISTICS
Electric:
Customers (Year-End) 476,438 468,901 461,928 453,687 446,544
Territorial Sales (Million KWH) 16,840 16,889 15,801 15,702 15,394
Residential:
Average annual use per customer
(KWH) 13,048 14,077 13,037 13,246 13,330
Average annual rate per KWH $.0743 $.0707 $.0695 $.0700 $.0707
Gas:
Customers (Year-End) 238,433 221,278 218,582 214,485 210,326
Sales (Thousand Therms) 322,837 267,335 256,495 247,483 252,373
Residential:
Average annual use per customer
(therms) 538 606 577 522 497
Average annual rate per therm $.84 $.76 $.74 $.77 $.77
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulatory
protection. The transition began with the enactment of the Public
Utility Regulatory Policies Act of 1978 which facilitated the entry
of competitors into the electric generation business.
Subsequently, NEPA was enacted in 1992 to promote competition among
utility and nonutility generators in the wholesale electric
generation market. Recent initiatives in some states to lessen
regulation and promote competition, particularly with regard to
retail transmission access, also have accelerated the utility
industry's transition.
Future deregulation of electric wholesale and retail markets
will create opportunities to compete for new and existing customers
and markets. As a result, profit margins and asset values of some
utilities could be adversely affected.
The pace of deregulation, the future market price of
electricity, and the regulatory actions which may be taken by the
PSC in response to the changing environment cannot be predicted.
However, the Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company
reorganized its operations around Strategic Business Units.
Maintaining a competitive cost structure is of paramount importance
in the utility's strategic plan. The Company has undertaken a
variety of initiatives, including reductions in operation and
maintenance costs and in staffing levels. The Company believes
that these actions as well as numerous others that have been and
will be taken demonstrate its ability and commitment to succeed in
the new operating environment to come.
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 generally 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 and is expected to be complete in late 1995
with commercial operation beginning in early 1996. The estimated
cost 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 2B 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 which was
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 estimated primary cash requirements for 1995, excluding
requirements for fuel liabilities and short-term borrowings
(including notes payable to affiliated companies), and the actual
primary cash requirements for 1994 are as follows:
1995 1994
(Thousands of Dollars)
Property additions and construction
expenditures, excluding allowance for
funds used during construction (AFC) $284,754 $378,912
Nuclear fuel expenditures 23,084 27,429
Maturing obligations, redemptions and
sinking and purchase fund requirements 20,616 5,060
Total $328,454 $411,401
21
Approximately 22% of total cash requirements (excluding
dividends) was provided from internal sources in 1994 as compared
to 20.0% in 1993.
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 are at least twice the
annual interest requirements on all Class A Bonds to be outstanding
(Bond Ratio). For the year ended December 31, 1994 the Bond Ratio
was 3.52. 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 $499.8 million at December 31, 1994), Class A Bonds
issued on the basis of retirements of Class A Bonds (no earned
retirement credits remained at December 31, 1994) 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 $57 million were available
for such purpose as of December 31, 1994), 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, 1994 the New Bond Ratio was 4.85.
The following financing transactions have occurred since
December 31, 1993:
On July 21, 1994 the Company issued $100 million of First
Mortgage Bonds, 7.70% series due July 15, 2004 to repay short-
term borrowings in a like amount.
On November 3, 1994 the Company issued $30 million of
Pollution Control Facilities Revenue Bonds due November 1,
2024. The proceeds from the sale of the bonds are being used
to defray the cost of constructing certain facilities for the
disposal of solid waste at the Company's Cope Generating
Station under construction in Orangeburg County, South
Carolina.
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, 1997.
The Company had $265.0 million authorized and unused lines of
credit at December 31, 1994. In addition, the Company has a
credit agreement for a maximum of $75 million to finance nuclear
and fossil fuel, with $24.4 million available at December 31, 1994.
Fuel Company has issued a promissory note due March
31, 1995 to SCANA for the purchase of $19.4 million of sulfur
dioxide emission allowances, including $0.6 million in AFC.
22
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 are at least one and one-half times the aggregate of all
interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1994 the
Preferred Stock Ratio was 2.29.
The Company anticipates that its 1995 cash requirements of
$328.5 million will be met through internally generated funds
(approximately 29.4% 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 1995 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.
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. At December 31,
1994, the Company had purchased $19.4 million in emission
allowances and had commitments to purchase $6.8 million of emission
allowances in 1995. Low nitrogen oxide burners will be installed
to reduce nitrogen oxide emissions.
The Company is continuing to refine a compliance plan that
must be filed with the U.S. Environmental Protection Agency (EPA)
by January 1, 1996. The Company currently estimates that,
excluding GENCO, air emissions control equipment will require
capital expenditures of $117 million over the 1995-1999 period to
retrofit existing facilities and an increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2004, the Company
anticipates total capital expenditures of approximately $205
million.
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a national
permit program. Discharge permits have been issued for all and
renewed for nearly all of the Company's and GENCO's generating
units. Concurrent with renewal of these permits, the permitting
agency has implemented more rigorous control programs. The Company
has 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.
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 differ significantly 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 for electric
operations and an eight-year period for gas operations. Such
deferred amounts totaled $20.2 million and $19.6 million at
December 31, 1994 and 1993, respectively. Estimates to date
include, among other things, the costs associated with the matters
discussed in the following paragraphs.
23
The Company owns five decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The Company
maintains an active review of the sites to monitor the nature and
extent of the residual contamination.
In September 1992 the EPA notified the Company, the City of
Charleston and the Charleston Housing Authority of their potential
liability for the investigation and cleanup of the Calhoun Park
Area Site in Charleston, South Carolina. This site originally
encompassed approximately 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 the EPA. The Company is
also working with the City of Charleston to investigate potential
contamination from the manufactured gas plant which may have
migrated to the City's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to be
responsible for a $43.5 million increase in costs of the aquarium
project attributable to delays resulting from contamination of the
Calhoun Park Area Site. The Company believes it has meritorious
defenses against this claim and does not expect its resolution to
have a material impact on its financial position or results of
operations.
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.
The Arkansas Department of Pollution Control and Ecology
(ADPCE) has identified the Company as a PRP for clean-up of PCBs at
an abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from ADPCE has been received concerning this
issue. The Company does not believe that the resolution of this
issue will have a material effect on the Company's results of
operations or financial position.
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, based
on a test year. These rates were 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 anticipates filing for electric rate relief in
1995. The filing is anticipated to encompass primarily the
remaining costs of completing the construction of the Cope
Generating Station.
The Company's regulated business operations are likely to be
impacted by the NEPA and FERC Order No. 636. NEPA is designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. 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.
24
RESULTS OF OPERATIONS
Overview
Net income and the percent increase (decrease) from the
previous year for the years 1994, 1993 and 1992 were as follows:
1994 1993 1992
Net income $152,043 $145,968 $102,163
Percent increase (decrease) in net
income 4.16% 42.9% (16.8%)
1994 Net income increased for 1994 primarily due to an increase
in the electric and gas margins which more than offset
increases in other operating expenses.
1993 Net income increased for 1993 primarily due to an increase
in the electric margin which more than offset increases in
other operating expenses.
The Company's financial statements include AFC. AFC is a
utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is
shown on the balance sheet as construction work in progress) is
capitalized. An equity portion of AFC is included in nonoperating
income and a debt portion of AFC is included in interest charges
(credits) as noncash items, both which have the effect of
increasing reported net income. AFC represented approximately 6.3%
of income before income taxes in 1994, 5.6% in 1993 and 5.5% in
1992.
Electric Operations
Electric sales margins for 1994, 1993 and 1992 were as
follows:
1994 1993 1992
(Millions of Dollars)
Electric revenues $974.3 $940.2 $844.5
(Provision) for rate refunds 1.2 0.3 (14.6)
Net Electric operating revenues 975.5 940.5 829.9
Less: Fuel used in electric generation 176.6 164.2 161.7
Purchased power 112.9 111.1 80.4
Margin $686.0 $665.2 $587.8
1994 The 1994 electric sales margin increased from 1993
primarily as a result of an increase in retail electric rates
phased in over a two-year period beginning in June 1993 and an
increase in industrial sales which more than offset the
negative impact of a six percent decrease in residential sales
of electricity due to milder weather in 1994.
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 against earnings recorded in 1992 related to
the August 31, 1992 retail electric rate ruling from the
Supreme Court (see Note 2F of Notes to Consolidated Financial
Statements).
Increases (decreases) in megawatt hour (MWH) sales volume by
classes are presented in the following table:
Increase (Decrease)
From Prior Year
Volume (MWH)
Classification 1994 1993
Residential (339,620) 494,874
Commercial 4,198 305,560
Industrial 274,467 203,178
Sale for Resale (excluding interchange) 18,408 59,611
Other (6,907) 24,873
Total territorial (49,454) 1,088,096
Interchange (27,013) 121,013
Total (76,467) 1,209,109
25
The electric sales volume decreased for the year ended
December 31, 1994 compared to the corresponding prior period as a
result of decreased residential kilowatt hour sales and interchange
power delivered due to milder weather in 1994. The peak demand of
3,444 MW was recorded on January 19, 1994. The all-time peak
demand record of 3,557 MW was set on July 29, 1993.
Gas Operations
Gas sales margins for 1994, 1993 and 1992 were as follows:
1994 1993 1992
(Millions of Dollars)
Gas revenues $201.7 $174.0 $160.8
Less: Gas purchased for resale 127.8 107.7 95.8
Margin $ 73.9 $ 66.3 $ 65.0
1994 The 1994 gas sales margin increased from 1993 primarily
as a result of increases in interruptible gas sales.
1993 The 1993 gas sales margin increased from 1992 primarily
as a result of increases in higher margin residential and
regular commercial sales.
Increases (decreases) in dekatherm (DT) sales volume by
classes, including transportation gas, are presented in the
following table:
Increase (Decrease)
From Prior Year
Volume (DT)
Classification 1994 1993
Residential (477,886) 723,356
Commercial 970,726 (186,529)
Industrial 5,057,404 547,193
Transportation Gas (1,524,089) 1,087,120
Total 4,026,155 2,171,140
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 1994 1993
(Millions of Dollars)
Other operation and maintenance $ 3.9 $ 8.1
Depreciation and amortization 5.7 4.2
Income taxes 2.8 29.9
Other taxes 5.0 (0.2)
Total $17.4 $42.0
1994 Other operation and maintenance expenses increased for
1994 primarily due to an increase in the costs of
postretirement benefits other than pensions. These costs are
accrued in accordance with Financial Accounting Standards
Board Statement No. 106 (See Note 1J of Notes to Consolidated
Financial Statements.) The increase in depreciation and
amortization expenses is attributable to property additions
and to increases in depreciation rates. The increase in other
taxes reflects an increase in property taxes of approximately
$5 million.
26
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.
Interest Expense
Increases (decreases) in interest expense are presented in the
following table:
Increase (Decrease)
From Prior Year
Classification 1994 1993
(Millions of Dollars)
Interest on long-term debt, net $8.0 $ (.8)
Other interest expense (.6) (1.0)
Total $7.4 $(1.8)
1994 The increase in interest expense, excluding the debt
component of AFC, is primarily attributable to the issuance of
$100 million of First Mortgage Bonds in July and $30 million
of Pollution Control Facilities Revenue Bonds in November,
both to finance utility construction, and to the issuance of
long-term debt during 1993.
1993 Interest expense, excluding the debt component of AFC,
decreased 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.
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, 1994 and 1993... 30
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1994, 1993 and 1992............. 32
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992............................. 33
Consolidated Statements of Capitalization as of
December 31, 1994 and 1993................................... 34
Notes to Consolidated Financial Statements..................... 36
Supplemental financial statement schedules are omitted because
of the absence of conditions under which they are required or
because the required information is included in the consolidated
financial statements or in the notes thereto.
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, 1994 and 1993 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,
1994. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion
on the financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company at December 31, 1994 and 1993 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1994 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 6, 1995
29
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1994 1993
(Thousands of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $3,165,391 $3,067,881
Gas 307,929 272,506
Transit 3,785 3,769
Common 77,327 72,804
Total 3,554,432 3,416,960
Less accumulated depreciation and amortization 1,171,758 1,097,531
Total 2,382,674 2,319,429
Construction work in progress 571,867 338,677
Nuclear fuel, net of accumulated amortization 43,591 29,087
Utility Plant, Net 2,998,132 2,687,193
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 11,931 12,709
Current Assets:
Cash and temporary cash investments (Note 8) 346 193
Receivables - customer and other 127,679 119,296
Receivables - affiliated companies (Note 1) 18,121 244
Inventories (at average cost):
Fuel (Notes 1, 3 and 4) 31,310 31,192
Materials and supplies 43,228 43,372
Prepayments 14,389 10,089
Accumulated deferred income taxes 17,931 9,015
Total Current Assets 253,004 213,401
Deferred Debits:
Emission allowances 19,409 -
Unamortized debt expense 11,690 11,060
Unamortized deferred return on plant investment (Notes 1 and 2) 10,614 14,860
Nuclear plant decommissioning fund (Note 1) 30,383 25,103
Other (Note 1) 251,928 225,613
Total Deferred Debits 324,024 276,636
Total $3,587,091 $3,189,939
See Notes to Consolidated Financial Statements.
30
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1994 1993
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment (Note 5):
Common equity $1,133,432 $1,051,334
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,159,459 1,077,361
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 49,528 52,840
Long-Term Debt, Net (Notes 3, 4 and 8) 1,219,991 1,097,043
Total Capitalization 2,428,978 2,227,244
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 111,200 1,011
Notes payable - affiliated companies 19,409 -
Current portion of long-term debt (Note 3) 33,042 13,719
Current portion of preferred stock (Note 6) 2,418 2,504
Accounts payable 61,466 68,182
Accounts payable - affiliated companies (Note 1 and 3) 33,357 28,630
Estimated rate refunds and related interest (Note 2) - 2,509
Customer deposits 12,668 12,207
Taxes accrued 46,646 39,965
Interest accrued 21,534 17,764
Dividends declared 28,489 29,982
Other 15,525 10,042
Total Current Liabilities 385,754 226,515
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 503,723 480,808
Accumulated deferred investment tax credits (Notes 1 and 7) 81,546 84,447
Accumulated reserve for nuclear plant decommissioning (Note 1) 30,383 25,103
Other (Note 1) 156,707 145,822
Total Deferred Credits 772,359 736,180
Total $3,587,091 $3,189,939
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, 1994 1993 1992
(Thousands of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $ 975,526 $ 940,547 $ 829,938
Gas 201,746 174,035 160,820
Transit 4,002 3,851 3,623
Total Operating Revenues 1,181,274 1,118,433 994,381
Operating Expenses:
Fuel used in electric generation 176,581 164,187 161,691
Purchased power (including affiliated
purchases)(Note 1) 112,900 111,111 80,431
Gas purchased from affiliate for resale (Note 1) 127,846 107,722 95,854
Other operation 214,344 207,126 199,819
Maintenance 57,801 61,107 60,279
Depreciation and amortization (Note 1) 106,952 101,220 97,064
Income taxes (Notes 1 and 7) 84,066 81,280 51,382
Other taxes (Note 12) 70,366 65,361 65,594
Total Operating Expenses 950,856 899,114 812,114
Operating Income 230,418 219,319 182,267
Other Income (Note 1):
Allowance for equity funds used during construction 7,989 7,496 4,577
Other income (loss), net of income taxes (718) (911) (1,571)
Total Other Income 7,271 6,585 3,006
Income Before Interest Charges 237,689 225,904 185,273
Interest Charges (Credits):
Interest on long-term debt, net 87,361 79,410 80,217
Other interest expense (Note 1 and 3) 5,189 5,812 6,777
Allowance for borrowed funds used
during construction (Note 1) (6,904) (5,286) (3,884)
Total Interest Charges, Net 85,646 79,936 83,110
Net Income 152,043 145,968 102,163
Preferred Stock Cash Dividends (At stated rates) (5,955) (6,217) (6,474)
Earnings Available for Common Stock 146,088 139,751 95,689
Retained Earnings at Beginning of Year 291,713 262,262 265,864
Common Stock Cash Dividends Declared (Note 5) (113,700) (110,300) (99,291)
Retained Earnings at End of Year $ 324,101 $ 291,713 $ 262,262
See Notes to Consolidated Financial Statements.
32
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994 1993 1992
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $152,043 $145,968 $102,163
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 107,103 101,370 97,212
Amortization of nuclear fuel 13,487 18,156 23,190
Deferred income taxes, net 13,133 56,982 (15,959)
Deferred investment tax credits, net (2,901) (3,245) (3,245)
Net regulatory asset arising from adoption of SFAS No. 109 (1,985) (40,398) -
Allowance for funds used during construction (14,893) (12,782) (8,461)
Unamortized loss on reacquired debt (129) (17,094) (112)
Early retirements (7,086) (11,840) -
Nuclear refueling accrual (4,881) (6,086) 11,862
Over (under) collections, fuel adjustment clause (17,965) (13,728) 7,901
Emission allowances (19,409) - -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (26,260) (27,920) 4,319
(Increase) decrease in inventories 26 1,401 1,069
Increase (decrease) in accounts payable (430) 16,757 2,526
Increase (decrease) in estimated rate
refunds and related interest (2,509) (15,302) 17,811
Increase (decrease) in taxes accrued 6,681 (11,162) 36
Increase (decrease) in interest accrued 3,770 (8,669) 83
Other, net 13,313 886 (2,457)
Net Cash Provided From Operating Activities 211,108 173,294 237,938
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures (420,947) (300,620) (243,329)
Nonutility property and investments (287) (248) (205)
Transfer of assets from SCANA 6,285 - -
Principal noncash item:
Allowance for funds used during construction 14,893 12,782 8,461
Net Cash Used For Investing Activities (400,056) (288,086) (235,073)
Cash Flows From Financing Activities:
Proceeds:
Issuance of notes payable - affiliated companies 19,409 - -
Issuance of mortgage bonds 100,000 600,000 -
Issuance of pollution control bonds 30,000 - -
Equity contributions from parent 43,426 58,142 126,838
Other Long-term debt - 2,562 -
Repayments:
Mortgage bonds - (430,000) (35,890)
Other Long-term debt (1,662) (405) (120)
Preferred stock (3,398) (3,295) (3,199)
Dividend Payments:
Common stock (115,100) (108,641) (96,550)
Preferred stock (6,048) (6,247) (6,558)
Short-term borrowings, net 110,189 978 (20)
Fuel financings, net 13,844 (18,948) (6,628)
Advances - affiliated companies, net (1,559) (3,463) (2,899)
Net Cash Provided From (Used For) Financing Activities 189,101 90,683 (25,026)
Net Increase (Decrease) in Cash and Temporary Cash Investments 153 (24,109) (22,161)
Cash and Temporary Cash Investments, January 1 193 24,302 46,463
Cash and Temporary Cash Investments, December 31 $ 346 $ 193 $ 24,302
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $6,904, $5,286 and $3,884) $ 87,255 $ 92,367 $ 86,093
- Income taxes 77,295 79,612 72,584
Noncash Financing Activities:
Department of Energy decontamination and decommissioning
fund obligation 4,277 4,965 -
See Notes to Consolidated Financial Statements.
33
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1994 1993
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 238,369 188,713
Capital stock expense (5,443) (5,497)
Retained earnings 324,101 291,713
Total Common Equity 1,133,432 47% 1,051,334 47%
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 1994 1993 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 1994 1993 Current Through Minimum
7.70% 89,984 92,992 101.00 - 101.00 8,998 9,299
8.12% 126,835 131,899 102.03 - 102.03 12,684 13,190
Total 216,819 224,891
$50 Par Value - Authorized 1,627,074 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
4.50% 19,088 20,800 51.00 - 51.00 954 1,040
4.60% 2,334 3,834 50.50 - 50.50 117 192
4.60%(A) 28,052 30,052 51.00 - 51.00 1,403 1,503
4.60%(B) 78,200 81,600 50.50 - 50.50 3,910 4,080
5.125% 73,000 74,000 51.00 - 51.00 3,650 3,700
6.00% 86,400 89,600 50.50 - 50.50 4,320 4,480
8.72% 127,956 160,000 51.00 12-31-98 50.00 6,398 8,000
9.40% 190,245 197,191 51.175 - 51.175 9,512 9,860
Total 605,275 657,077
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1994 and 1993
Total Preferred Stock (Subject to purchase or sinking funds) 51,946 55,344
Less: Current portion, including sinking fund requirements 2,418 2,504
Total Preferred Stock, Net (Subject to purchase or sinking funds) 49,528 2% 52,840 3%
See Notes to Consolidated Financial Statements.
34
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1994 1993
(Thousands of Dollars)
Long-Term Debt (Notes 3, 4 and 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100,000 100,000
6 1/4% 2003 100,000 100,000
7 1/8% 2013 150,000 150,000
7 1/2% 2023 150,000 150,000
7 5/8% 2023 100,000 100,000
7.70% 2004 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
7 1/4% 2002 30,000 30,000
9% 2006 145,000 145,000
8 7/8% 2021 155,000 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,660 6,760
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365
Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 -
Capitalized Lease Obligations, due 1991-1997 (various rates between
5 3/4% and 10%) 1,842 2,897
Installment Note Payable, due 1996 1,452 2,277
Department of Energy Decontamination and Decommissioning Obligation 3,922 4,634
Nuclear and Fossil Fuel Liability 50,594 36,750
Total 1,257,955 1,116,803
Less: Current maturities, including sinking fund requirements 33,042 13,719
Unamortized discount 4,922 6,041
Total Long-Term Debt, Net 1,219,991 50% 1,097,043 49%
Advances from Affiliated Companies - 1,559
Less: Current portion of advances - affiliated companies - 1,559
Advances from Affiliated Companies, Net - - -
Total Capitalization $2,428,978 100% $2,227,244 100%
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, 1994 and
1993 the Company had approximately $16.3 million and $15.1
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, 1994 and 1993 the Company had
approximately $8.8 million and $7.5 million, respectively,
payable to GENCO for unit power purchases. Such unit power
purchases, which are included in "Purchased power," amounted to
approximately $92.8 million, $98.1 million and $73.1 million in
1994, 1993 and 1992, respectively.
Fuel Company has issued a promissory note due March 31, 1995
to SCANA for the purchase of $19.4 million of sulfur dioxide
emission allowances, including $0.6 million in AFC.
Total interest income (expense), based on market interest
rates, associated with the Company's advances to affiliated
companies was approximately $(8,000), $129,000 and $231,000 in
1994, 1993 and 1992, respectively.
Included in "Other interest expense" for 1994, 1993 and 1992
is approximately $279,000, $29,000 and $16,000, 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.
36
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 $923.1 million and $920.2
million as of December 31, 1994 and 1993, respectively.
Accumulated depreciation associated with the Company's share of
Summer Station was approximately $297.9 million and $285.3
million as of December 31, 1994 and 1993, respectively. The
Company's share of the direct expenses associated with operating
Summer Station is included in "Other operation" and "Maintenance"
expenses.
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 8.5%,
9.4% and 9.4% for 1994, 1993 and 1992, respectively. These rates
do not exceed the maximum allowable rate as calculated under FERC
Order No. 561. Interest on nuclear fuel in process and sulfur
dioxide emission allowances is capitalized at the actual interest
amount.
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 1994, 1993 and 1992.
F. Revenue Recognition
Customers' meters are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the
accounting period in which the meters are read.
Fuel costs for electric generation are collected through the
fuel cost component in retail electric rates. The fuel cost
component contained in electric rates is established by the PSC
during semiannual fuel cost hearings. Any difference between
actual fuel costs and that contained in the fuel cost component
is deferred and included when determining the fuel cost component
during the next semiannual fuel cost hearing. The Company had
undercollected through the electric fuel cost component
approximately $3.5 million at December 31, 1994 and overcollected
approximately $9.2 million at December 31, 1993 which are
included in "Deferred Debits-Other" and "Deferred Credits-Other",
respectively.
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, 1994 and 1993 the Company had
undercollected through the gas cost recovery procedure
approximately $16.3 million and $11.0 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 3.01%, 2.97%,
and 3.00% for 1994, 1993 and 1992, 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 a 4.5% annual rate of inflation, to be
$545.3 million including partial reclamation costs. The Company
is providing for its share of estimated decommissioning costs of
Summer Station over the life of Summer Station. The Company's
method of funding decommissioning cost is referred to as COMReP
(Cost of Money Reduction Plan). Under this plan, funds collected
through rates ($3.2 million and $2.5 million in 1994 and 1993,
respectively) are used to purchase insurance policies on the
lives of key Company personnel. Through the purchase of
insurance contracts, the Company is able to take advantage of
income tax benefits and accrue earnings on the fund on a tax-
deferred basis at a rate higher than can be achieved using more
traditional funding approaches. Amounts for decommissioning
collected through electric rates, insurance proceeds, and
interest on proceeds less expenses are transferred by the Company
to an external trust fund in compliance with the financial
assurance requirements of the Nuclear Regulatory Commission.
Management intends for the fund, including earnings thereon, to
provide for all eventual decommissioning expenditures on an
after-tax basis. Thus, the trust's sources of decommissioning
funds under the COMReP program include investment components of
life insurance policy proceeds, return on investments, and the
cash transfers from the Company described above. The Company
records its liability for decommissioning costs in deferred
credits.
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the
electric utility industry regarding the recognition, measurement
and classification of decommissioning costs for the financial
statements of electric utilities with nuclear generating
facilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting
for removal costs, including decommissioning. If the current
electric utility industry accounting practices for such
decommissioning are changed: (1) annual provisions for
decommissioning could increase, and (2) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction of decommissioning
expense.
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. The Company
will recover the costs associated with this liability, totaling
$4.3 million at December 31, 1994, 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 expected 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. At December 31,
1993, 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 effects of temporary
differences between the book basis and tax basis of assets and
liabilities at currently enacted tax rates. Deferred tax assets
and liabilities are adjusted for changes in such rates through
charges or credits to regulatory assets or liabilities if they
are expected to be recovered from, or passed through to,
customers; otherwise, they are charged or credited to income tax
expense.
38
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.
Net periodic pension cost for the years ended
December 31, 1994, 1993 and 1992 included the following
components:
1994 1993 1992
(Thousands of Dollars)
Service cost--benefits earned during the period $ 8,684 $ 7,629 $ 7,174
Interest cost on projected benefit obligation 21,711 20,413 19,628
Adjustments:
Return on plan assets 2,365 (50,389) (28,607)
Net amortization and deferral (29,760) 25,936 8,096
Amounts contributed by the Company's
affiliates (130) (175) (154)
Net periodic pension cost $ 2,870 $ 3,414 $ 6,137
The determination of net periodic pension cost is based upon
the following assumptions:
1994 1993 1992
Annual discount rate 7.25% 8.0% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 4.75% 5.5% 5.5%
The following table sets forth the funded status of the plan
at December 31, 1994 and 1993:
1994 1993
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $205,364 $204,794
Nonvested benefit obligation 13,966 14,085
Accumulated benefit obligation $219,330 $218,879
Plan assets at fair value
(invested primarily in equity and debt securities) $347,702 $351,648
Projected benefit obligation 246,318 295,718
Plan assets greater than
projected benefit obligation 101,384 55,930
Unrecognized net transition liability 11,307 10,713
Unrecognized prior service costs 9,374 9,294
Unrecognized net gain (102,284) (64,607)
Pension asset recognized in
Consolidated Balance Sheets $ 19,781 $ 11,330
The accumulated benefit obligation is based on the plan's
benefit formulas without considering expected future salary
increases. The following table sets forth the assumptions used
in determining the amounts shown above for the years 1994, 1993
and 1992.
1994 1993 1992
Annual discount rate used to determine
benefit obligations 8.0% 7.25% 8.0%
Assumed annual rate of future salary increases
for projected benefit obligation 2.5% 4.75% 5.5%
39
The change in the annual discount rate used to determine
benefit obligations from 7.25% to 8.0% and the change in the
expected salary increase rate from 4.75% to 2.5% as of December
31, 1994 decreased the projected benefit obligation and increased
the unrecognized net gain by approximately $67.7 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. The costs of postretirement benefits
other than pensions are accrued during the years the employees
render the service necessary to be eligible for the applicable
benefits. Prior to 1993, the Company expensed these benefits,
which are primarily health care, as claims were incurred. In its
June 1993 electric rate order the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. The Company expensed approximately $8.6 million and
$4.3 million, net of payments to current retirees, for the years
ended December 31, 1994 and 1993, respectively.
Net periodic postretirement benefit cost for the years ended
December 31, 1994 and 1993, included the following components:
1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 2,417 $ 1,908
Interest cost on accumulated postretirement benefit
obligation 6,644 5,502
Adjustments:
Return on plan assets - -
Amortization of unrecognized transition obligation 3,344 3,344
Other net amortization and deferral 860 -
Amounts contributed by the Company's affiliates (575) (525)
Net periodic postretirement benefit cost $12,690 $10,229
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1994 1993
Annual discount rate 7.25% 8.0%
Health care cost trend rate 11.25% 13.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 5.25% 6.0%
The following table sets forth the funded status of the plan
at December 31, 1994 and 1993:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 59,174 40,865
Other fully eligible participants 4,995 6,841
Other active participants 24,889 25,767
Accumulated postretirement benefit obligation 89,058 73,473
Plan assets at fair value - -
Plan assets less accumulated postretirement benefit
obligation (89,058) (73,473)
Unrecognized net transition liability 61,581 64,925
Unrecognized prior service costs 3,453 -
Unrecognized net loss 11,156 4,284
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(12,868) (4,264)
40
The accumulated postretirement benefit obligation is based
upon the plan's benefit provisions and the following assumptions:
1994 1993
Assumed health care cost trend rate used to
measure expected costs 12.0% 11.25%
Ultimate health care cost trend rate
(to be achieved in 2004) 6.0% 5.25%
Annual discount rate 8.0% 7.25%
Annual rate of salary increases 2.5% 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,
1994 and the accumulated postretirement benefit obligation
as of December 31, 1994 would be to increase such amounts by
$210,000 and $3.3 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.
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 differ
significantly 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 for electric operations and an eight-year period for gas
operations. Such deferred amounts totaled $20.2 million and
$19.6 million at December 31, 1994 and 1993, respectively, and
are included in "Deferred Debits-Other."
M. Fuel Inventories
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. Temporary Cash Investments
The Company considers temporary cash investments having
original maturities of three months or less to be cash
equivalents. Temporary cash investments are generally in the
form of commercial paper, certificates of deposit and repurchase
agreements.
O. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1994 presentation.
41
2. RATE MATTERS:
A. On October 27, 1994 the PSC issued an order approving the
Company's request to recover through a billing surcharge to its
gas customers the costs of environmental cleanup at the sites of
former manufactured gas plants. The billing surcharge, which was
effective with the first billing cycle in November 1994 and is
subject to annual review, provides for the recovery of
approximately $16.2 million representing substantially all site
assessment and cleanup costs for the Company's gas operations
that had previously been deferred.
B. 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 were 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.
C. 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.
D. Effective with the first billing cycle in December 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 is subject
to annual review by the PSC. The PSC order was based on a
return on common equity of 12.25%. On August 26, 1994, the PSC
ordered that the WNA be made permanent.
E. 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. On April 30, 1994 the PSC
issued an order involving Pipeline Corporation's recovery of
take-or-pay cost incurred pursuant to FERC-approved settlements
with its upstream interstate pipeline supplier. This order
provided a mechanism for Pipeline Corporation to recover its
take-or-pay cost volumetrically over a period of approximately 30
months. The Company receives a credit for payments made prior to
the April 30 order which is netted against the current volumetric
surcharge. That net cost is recovered by the Company through its
purchased gas adjustment clause.
F. 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
nonmaterial 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.
42
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 1995 through 1999
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1995 $33,042 1998 $35,224
1996 82,229 1999 15,234
1997 30,244
Approximately $14.8 million of the portion of long-term debt
payable in 1995 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.
Certain outstanding long-term debt of an affiliated
company (approximately $35.9 million at both December 31, 1994
and 1993) 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 $50.6 million and $36.8
million at December 31, 1994 and 1993 at weighted average
interest rates of 6.06% and 3.47%, 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
1994, 1993 and 1992 are summarized as follows:
Common Preferred Thousands
Shares Shares of Dollars
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
Changes in Retained Earnings:
Net Income 152,043
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,955)
Common Stock (113,700)
Equity Contributions from Parent
including transfer of assets 49,710
Balance December 31, 1994 40,296,147 322,877 $1,159,459
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, 1994
approximately $13.2 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 1995 through
1999 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1995 $2,418 1998 $2,440
1996 2,482 1999 2,440
1997 2,440
The changes in "Total Preferred Stock (Subject to Purchase or Sinking
Funds)" during 1994, 1993 and 1992 are summarized as follows:
Number Thousands
of Shares of Dollars
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
Shares Redeemed:
$100 par value (8,072) (807)
$50 par value (51,802) (2,591)
Balance December 31, 1994 822,094 $ 51,946
7. INCOME TAXES:
Total income tax expense for 1994, 1993 and 1992 is as follows:
1994 1993 1992
(Thousands of Dollars)
Current taxes:
Federal $66,597 $60,577 $62,147
State 9,505 6,822 7,852
Total current taxes 76,102 67,399 69,999
Deferred taxes, net:
Federal 7,727 12,197 (16,274)
State 2,118 4,387 (322)
Total deferred taxes 9,845 16,584 (16,596)
Investment tax credits:
Amortization of amounts
deferred (credit) (3,231) (3,245) (3,245)
Total income tax expense $82,716 $80,738 $50,158
45
The difference in actual income taxes and the income taxes
calculated from the application of the statutory Federal income tax
rate (35% for 1994 and 1993 and 34% for 1992) to pretax income is
reconciled as follows:
1994 1993 1992
(Thousands of Dollars)
Net income $152,043 $145,968 $102,163
Total income tax expense:
Charged to operating expenses 84,066 81,280 51,382
Charged (credited) to other income (1,350) (542) (1,224)
Total pretax income $234,759 $226,706 $152,321
Income taxes on above at statutory Federal
income tax rate $ 82,166 $ 79,347 $ 51,789
Increases (decreases) attributable to:
Allowance for funds used during construction
(excluding nuclear fuel) (2,796) (2,624) (1,556)
Deferred return on plant investment,
net of amortization 1,486 1,486 1,444
Depreciation differences 2,994 2,531 2,356
Amortization of investment tax credits (3,231) (3,245) (3,245)
State income taxes (less Federal
income tax effect) 7,555 7,286 4,970
Deferred income tax flowback at higher
than statutory rates (3,647) (3,641) (4,914)
Other differences, net (1,811) (402) (686)
Total income tax expense $ 82,716 $ 80,738 $ 50,158
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 operations was not
material.
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $485.8
million at December 31, 1994 and $471.8 million at December 31, 1993
determined in accordance with Statement No. 109 (see Note 1I) are as
follows:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 50,513 $ 52,310
Cycle billing 17,521 15,084
Nuclear operations expenses 206 4,908
Deferred compensation 5,450 5,265
Other postretirement benefits 3,187 1,631
Other 3,627 4,532
Total deferred tax assets 80,504 83,730
Deferred tax liabilities:
Property plant and equipment (including
DD&A and basis differences) 533,394 526,540
Pension expense 9,022 6,266
Deferred fuel revenue 7,803 931
Reacquired debt 7,146 7,574
Other 8,931 14,212
Total deferred tax liabilities 566,296 555,523
Net deferred tax liability $485,792 $471,793
46
"Total deferred taxes" charged (credited) to income tax expense
result from timing differences in recognition of the following
items (thousands of dollars):
1992
Charged (credited) to expense:
Property plant and equipment (including
DD&A and basis differences) $ (5)
Deferred fuel revenue (2,947)
Property taxes 493
Cycle billing (1,381)
Nuclear refueling accrual (4,430)
Electric rate refund (6,571)
Injuries and damages (1,377)
Other, net (378)
Total deferred taxes $(16,596)
The Internal Revenue Service has examined and closed consolidated
Federal income tax returns of SCANA Corporation through 1989 and is
currently examining SCANA's 1990, 1991 and 1992 Federal income tax
returns. 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, 1994 and 1993 are as follows:
1994 1993
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Cash and temporary cash investments $ 346 $ 346 $ 193 $ 193
Investments 61 61 61 61
Short-term borrowings 111,200 111,200 1,011 1,011
Notes payable - affiliated companies 19,409 19,409 - -
Total Long-term debt 1,219,991 1,183,823 1,097,043 1,194,522
Total Preferred stock (subject to
purchase or sinking funds) 51,946 49,348 55,344 51,618
The information presented herein is based on pertinent information
available to the Company as of December 31, 1994 and 1993. 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, 1994, 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, 1994, 1993 and 1992 and for the years then ended are as
follows:
1994 1993 1992
(Millions of dollars)
Authorized lines of credit at year-end $265.0 $212.0 $189.9
Unused lines of credit at year-end $265.0 $212.0 $189.9
Short-term borrowings outstanding at
year-end:
Commercial paper $111.2 $ 1.0 $ -
Weighted average interest rate 6.04% 3.35% -
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
The Company entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina in Orangeburg
County. Construction of the plant began in November 1992 and is
expected to be complete in late 1995 with commercial operation
beginning in early 1996. The estimated cost 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.
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, 1994 is as follows (thousands
of dollars):
1995 $59,766
1996 5,603
Total $65,369
Through December 31, 1994 the Company had paid $310 million under
the contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with the
Company's public liability for a nuclear incident, currently
establishes the liability limit for third-party claims associated
with any nuclear incident at $8.9 billion. Each reactor licensee
is currently liable for up to $79.3 million per reactor owned for
each nuclear incident occurring at any reactor in the United
States, provided that not more than $10 million of the liability
per reactor would be assessed per year. The Company's maximum
assessment, based on its two-thirds ownership of Summer Station,
would be approximately $52.9 million per incident, but not more
than $6.7 million per year.
48
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 $8.2 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and
expenses arising from a nuclear incident at Summer Station exceed
the policy limits of insurance, or to the extent such insurance
becomes unavailable in the future, and to the extent that the
Company's rates would not recover the cost of any purchased
replacement power, the Company will retain the risk of loss as a
self-insurer. The Company has no reason to anticipate a serious
nuclear incident at Summer Station. If such an incident were to
occur, it could have a materially adverse impact on the Company's
financial position.
C. Environmental
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 differ
significantly from the original estimates. Amounts estimated and
accrued to date for site assessment 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 for electric operations and an eight-year period for gas
operations.
In September 1992 the Environmental Protection Agency (EPA)
notified the Company, the City of Charleston and the Charleston
Housing Authority of their potential liability for the
investigation and cleanup of the Calhoun Park Area Site in
Charleston, South Carolina. This site 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 which may have migrated to the city's aquarium site. In
1994 the City of Charleston notified the Company that it
considers the Company to be responsible for a $43.5 million
increase in costs of the aquarium project attributable to delays
resulting from contamination of the Calhoun Park Area Site. The
Company believes it has meritorious defenses against this claim
and does not expect its resolution to have a material impact on
its financial position or results of operations.
D. Emission Allowance
The Company has entered into an agreement with a broker of
sulfur dioxide emission allowances to purchase $6.8 million of
allowances at a fixed price during 1995.
49
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1994, 1993 and 1992 and for
the years then ended is as follows:
1994
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $975,526 $201,746 $ 4,002 $1,181,274
Operating expenses,
excluding depreciation
and amortization 659,610 173,717 10,577 843,904
Depreciation and
amortization 95,666 11,060 226 106,952
Total operating expenses 755,276 184,777 10,803 950,856
Operating income (loss) $ 220,250 $ 16,969 $ (6,801) 230,418
Add - Other income, net 7,271
Less - Interest charges 85,646
Net income $ 152,043
Capital expenditures:
Identifiable $ 359,510 $ 40,923 $ 347 $ 400,780
Utilized for overall Company operations 20,167
Total $ 420,947
Identifiable assets at
December 31, 1993:
Utility plant, net $2,717,147 $201,018 $ 1,791 $2,919,956
Inventories 85,113 2,605 495 88,213
Total $2,802,260 $203,623 $ 2,286 3,008,169
Other assets 578,922
Total assets $3,587,091
50
1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,547 $174,035 $ 3,851 $1,118,433
Operating expenses,
excluding depreciation
and amortization 639,808 148,349 9,737 797,894
Depreciation and
amortization 91,142 9,903 175 101,220
Total operating expenses 730,950 158,252 9,912 899,114
Operating income (loss) $ 209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585
Less - Interest charges 79,936
Net income $ 145,968
Capital expenditures:
Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934
Total $ 300,620
Identifiable assets at
December 31, 1993:
Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603
Inventories 66,181 2,526 463 69,170
Total $2,511,647 $180,990 $2,136 2,694,773
Other assets 495,166
Total assets $3,189,939
51
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
Other assets 368,626
Total assets $2,890,953
52
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1994
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $313,321 $263,033 $327,066 $277,854 $1,181,274
Operating income 63,520 43,316 79,133 44,449 230,418
Net Income 45,340 24,348 57,619 24,736 152,043
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
53
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, 1994 to hold
office until the next annual meeting of the Company's stockholder on
April 28, 1995.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 51 For more than five years, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).
For more than five years, Chairman and Chief
Executive Officer of Amick Processing,
Inc. and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia,
SC.
William B. Bookhart, Jr. 53 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 65 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC;
South Carolina National Corporation,
Columbia, SC; Wachovia Bank of South
Carolina, N.A., Columbia, SC.
Hugh M. Chapman 62 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.
54
Name and Year First
Became Director Age Principal Occupation; Directorships
James B. Edwards, D.M.D. 67 President and Professor of Maxillofacial
(1986) Surgery, Medical University of South
Carolina, Charleston, SC.
U.S. Secretary of Energy from January 1981
to November 1982.
Governor of South Carolina, 1975-1979.
Director, Phillips Petroleum Co.,
Bartlesville, OK; Brendle's,
Inc., Elkin, NC; Chemical Waste
Management, Inc., Chicago, IL; Imo
Industries, Inc., Lawrenceville, NJ;
Wachovia Bank of SC, Columbia, SC;
National Data Corporation, Atlanta, GA;
Encyclopedia Britannica, Chicago, IL;
SCANA Corporation, Columbia, SC.
Elaine T. Freeman 59 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg,
SC.
Director National Bank of South Carolina,
Columbia, S.C.; SCANA Corporation,
Columbia, SC.
Lawrence M. Gressette, Jr. 63 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.
Director, Wachovia Corporation, Winston-
Salem, NC; The Liberty Corporation,
Greenville, SC; SCANA Corporation,
Columbia, SC.
Benjamin A. Hagood 67 Since January 1, 1993, Chairman of the
(1974) Board, William M. Bird and Company, Inc.,
Charleston, SC (wholesale distributor of
floor covering material).
For more than three years prior to
January 1, 1993, President and Director,
William M. Bird and Company, Inc.,
Charleston, SC.
Director, SCANA Corporation, Columbia, SC.
55
Name and Year First
Became Director Age Principal Occupation; Directorships
W. Hayne Hipp 55 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 52 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 65 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. 66 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Third National Bank, Nashville,
TN; SCANA Corporation, Columbia, SC.
John B. Rhodes 64 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 48 Since May 1, 1994, Executive Vice President
(1991) of SCANA Corporation.
Since August 25, 1993, Assistant Secretary
of SCANA Corporation and all of its
subsidiaries including the Company.
Since August 28, 1991, Chief Financial
Officer of the Company.
For more than five years prior to May 1,
1994, Senior Vice President and Controller
of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC.
56
Name and Year First
Became Director Age Principal Occupation; Directorships
E. Craig Wall, Jr. 57 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.
57
EXECUTIVE OFFICERS OF THE COMPANY
The Company's officers are elected at the annual organizational meeting
of the Board of Directors and hold office until the next such organizational
meeting, unless the Board of Directors shall otherwise determine, or unless a
resignation is submitted.
Positions Held During
Name Age Past Five Years Dates
L.M. Gressette, Jr. (1) 63 Chairman of the Board and
Chief Executive Officer *-present
B.D. Kenyon (1) 52 President and Chief
Operating Officer 1990-present
Senior Vice President -
Division Operations,
Pennsylvania Power and
Light Company *-1990
W.B. Timmerman (1) 48 Executive Vice President, 1994-present
SCANA
Assistant Secretary 1993-present
Chief Financial Officer 1991-present
Senior Vice President, *-1994
SCANA
Chief Financial Officer
and Controller, SCANA *-present
G.J. Bullwinkel, Jr. 46 Senior Vice President-
Retail Electric 1995-present
Senior Vice President-
Fossil & Hydro Production 1993-1994
Senior Vice President-
Production 1991-1992
Vice President-Customer
Relations, Southern Division *-1991
J. L. Skolds 44 Senior Vice President -
Generation 1994-present
Vice President - Nuclear
Operations 1990-1994
General Manager - Nuclear
Plant Operations *-1990
W.A. Darby 49 Senior Vice President and
General Manager of ServiceCare,
Inc., a sister corporation 1994-present
Vice President-Gas Operations *-present
*Indicates position held at least since March 1, 1990
(1) Also an executive officer of SCANA
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Each of the executive officers and directors of the Company, listed
on pages 54-58, were delinquent in the filing of a Form 3, as
required by Section 16(a) of the Exchange Act, regarding the
ownership of the Company's equity securities. All of the Company's
common stock is held by its parent, SCANA Corporation, and none of
the directors and executive officers of the Company own any of the
other classes of equity securities of the Company. The required
forms, to be filed shortly, will indicate that no equity securities
of the Company are owned by the directors and executive officers.
58
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 1994, 1993 and
1992 to the Chief Executive Officer of the Company and to each of the
other four most highly compensated executive officers of the Company
during 1994 who were serving as executive officers of the Company at
the end of 1994.
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term
Compensation
Name and principal position
Year
Other annual1 Payouts All other
Salary Bonus compensa- LTIP2 compensa-
($) ($) tion ($) tion ($)
L. M. Gressette, Jr. 1994 416,6094 0 2,255 173,375 24,996
Chairman of the Board, 1993 383,557 186,615 61,6995 266,007 23,013
President, Chief Executive 1992 368,426 0 60,448 82,151 22,104
Officer and Director -
SCANA Corporation and the
Company and Chairman of
the Board and Chief Executive
Officer - all SCANA
subsidiaries
B. D. Kenyon 1994 313,581 96,768 2,649 81,619 18,815
President and Chief Operating 1993 297,760 99,090 4,201 125,792 17,866
Officer 1992 291,355 0 3,265 46,250 17,481
Director - SCANA Corporation
and the Company
W. B. Timmerman 1994 235,099 19,725 1,323 70,751 14,106
Executive Vice President 1993 220,752 95,738 2,828 109,768 13,245
Chief Financial Officer and 1992 215,817 0 2,303 33,906 12,949
Director - SCANA Corporation
Chief Financial Officer and
Director - SCANA Corporation
and the Company
J. H. Young 1994 174,771 50,765 318 45,251 10,486
Senior Vice President 1993 167,566 51,975 1,542 70,508 10,054
Customer Relations 1992 165,102 0 1,084 23,556 9,906
R. W. Stedman 1994 179,020 50,765 21 45,251 10,741
Senior Vice President - 1993 170,361 51,975 1,107 70,508 10,222
Administrative Support Group 1992 167,259 0 985 23,556 10,036
1 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. In 1992 and 1993 the perquisites for Mr.
Gressette included premiums on a whole life insurance policy in
the amount of $50,018.
2 Payments under the long-term Performance Share Plan described
hereafter.
3 All other compensation consists solely of Company contributions
to defined contribution plans on behalf of the named individual.
4 Reflects actual salary paid in 1994. Base salary of $427,100
became effective in May of 1994.
5 Adjusted from 1993 10-K to include perquisites amounting to
$4,324 not previously reflected.
59
Long-Term Performance Share Plan
SCANA's Performance Share Plan for officers of SCANA and its subsidiaries
measures SCANA's Total Shareholder Return ("TSR") relative to a group of peer
companies over a three-year period. The "PSP Peer Group" includes 95 electric
and gas utilities, none of which have annual revenues of less than $100
million.
TSR is stock price increase over the three-year period, plus cash
dividends paid during the period, divided by stock price as of the beginning
of the period. Comparing SCANA's TSR to the TSR of a large group of other
utilities reflects SCANA's recognition that investors could have
invested their funds in other utility companies and measures how well SCANA
did when compared to others operating in similar interest, tax, economic
and regulatory environments.
Executives eligible to participate in the Performance Share Plan are
assigned target award opportunities 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. 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 a combination of stock and cash.
For the three-year period from 1992 through 1994, SCANA's TSR was at the
61st percentile of the PSP Peer Group. This resulted in payouts in February
1995 at 122% of target shares awarded paid in a combination of stock and cash.
The following table shows the target awards made in 1994 for potential
payment in 1997 under the long-term Performance Share Plan, and estimated
future payouts under that plan at threshold, target and maximum levels.
LONG-TERM INCENTIVE PLAN - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1994 TO BE PAID IN 1997
Estimated Future Payouts
Under Non-Stock Price-
Based Plans
Number of Performance or
Shares, Units Other Period
Name or Other Rights Until Maturation Threshold Target Maximum
(#) or Payout ($ or #) ($ or #) ($ or #)
L. M. Gressette, Jr. 3,430 1994 - 1996 1,372 3,430 5,145
B. D. Kenyon 1,520 1994 - 1996 608 1,520 2,280
W. B. Timmerman 1,320 1994 - 1996 528 1,320 1,980
J. H. Young 800 1994 - 1996 320 800 1,200
R. W. Stedman 800 1994 - 1996 320 800 1,200
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.
60
The following table illustrates the estimated maximum annual
benefits payable upon retirement at normal retirement date under the
Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$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
550,000 162,473 216,631 270,788 324,946 337,854
The compensation shown in the column labeled "Salary" of the
Summary Compensation Table for the individuals named therein is
covered by the Retirement Plan and/or a SERP. Messrs. Gressette,
Kenyon, Timmerman, Young and Stedman now have credited service
under the Retirement Plan (or its equivalent under the SERP) of
32, 21, 16, 32 and 23 years, respectively. Benefits are computed
based on a straight-life annuity with an unreduced 60% surviving
spouse benefit. The amounts in this table assume continuation of
the primary Social Security benefits in effect at January 1, 1995
and are not subject to any deduction for Social Security or other
offset amounts.
The Company also has a Key Employee Retention Program (the
"Key Employee Retention Program") covering officers and certain
other executive employees that provides supplemental retirement
and/or death benefits for participants. Under the program, each
participant may elect to receive either a monthly retirement
benefit for 180 months upon retirement at or after age 65 equal
to 25% of the average monthly salary of the participant over his
final 36 months of employment prior to age 65, or an optional
death benefit payable to a participant's designated beneficiary
monthly for 180 months, in an amount equal to 35% of the average
monthly salary of the participant over his final 36 months of
employment prior to age 65. In the event of the participant's
death prior to age 65, the Company will pay to the participant's
designated beneficiary for 180 months, a monthly benefit equal to
50% of such participant's base monthly salary in effect at death.
All of the executive officers named in the Summary
Compensation Table above are participating in the program.
Estimated annual retirement benefits payable at age 65 based on
projected eligible compensation (assuming increases of 4% per
year) to the five executive officers named in the Summary
Compensation Table are as follows: Mr. Gressette - $111,102;
Mr. Kenyon - $127,564; Mr. Timmerman - $108,112; and Young -
$56,018. Mr. Stedman retired from the Company effective February
1, 1995 and is receiving an annual benefit of $44,497.
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.
61
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There currently exists one executive officer-director
interlock where an executive officer of SCANA Corporation serves
as a director of another company that has an executive officer
serving on the SCANA Board of Directors' committees which deal
with compensation matters. Mr. Gressette, Chairman of the Board,
Chief Executive Officer and President of the Company began
serving as a director of The Liberty Corporation in May 1994.
Mr. Hipp is President and Chief Executive Officer of The Liberty
Corporation and currently serves as a member of the Management
Development and Corporate Performance Committee and the Long-Term
Compensation Committee of the Board of Directors which generally
handle executive compensation matters. Mr. Gressette is an ex-
officio, 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. Since January 1, 1994, the Company has engaged in
business transactions with entities with which Messrs. Hipp,
Chapman (who is Chairman of the Performance Committee and a
member of the Long-Term Compensation Committee), and McMaster
(who is a member of the Long-Term Compensation Committee) are
related. Information with respect to such transactions can be
found in the paragraphs below.
Mr. Hipp is the President, Chief Executive Officer and a
director of The Liberty Corporation. In January 1994, SCANA and
its wholly owned subsidiary SCANA Development Corporation ("SDC")
entered into an agreement, amended in March 1994, to sell certain
of the assets of SDC to Liberty Properties Group, Inc., a
subsidiary of The Liberty Corporation, for approximately
$49 million. Closing of the transaction was completed in May
1994. The sale price by SCANA was determined by reference to
prices of comparable properties in the same market areas, as
negotiated by senior executives of the parties at arms length.
An independent certified public accounting firm was retained to
review the valuation methodology.
In addition, during 1994 certain of the insurance policies
purchased by SCANA and its subsidiaries on the lives of
employees, officers and directors of the Company 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 1994 by
SCANA and its subsidiaries to Liberty Life Insurance Company was
$360,785.42.
Mr. Chapman is Chairman of NationsBank South, a division of
NationsBank Corporation. Since January 1, 1994, SCANA and its
subsidiaries, including the Company have engaged in various
transactions in which affiliates of NationsBank Corporation acted
as lender or provider of lines of credit or credit support to the
Company and its subsidiaries. It is anticipated that such
transactions will continue in the future. The total amount paid
during 1994 by the Company and its subsidiaries to NationsBank
Corporation affiliates on account of such transactions was
$1,633,503.45.
In addition, in January 1995, a NationsBank Corporation
affiliate and SCANA entered into a series of forward contracts
relating to approximately sixty percent of SCANA's subsidiary's
forecasted natural gas production for the years 1995 - 2001, at
an average price of $1.88 per dekatherm.
Mr. McMaster is the President and Manager of Winnsboro
Petroleum Company. Purchases from Winnsboro Petroleum Company
totaling $98,464.06 for fuel oil and gasoline were made during
1994 by the Company and its subsidiaries. It is anticipated that
such purchases will continue in the future.
COMPENSATION OF DIRECTORS
Fees
During 1994, directors who were not employees of the Company
were paid $16,000 annually for services rendered, plus $1,800 for
each Board meeting attended and $850 for attendance at a
committee meeting which is not held on the same day as a regular
meeting of the Board. The fee for attendance at a telephone
conference meeting is $200. The fee for attendance at a
conference is $850. In addition, directors are paid, as part of
their compensation, travel, lodging and incidental expenses
related to attendance at meetings and conferences. Directors who
are employees of SCANA or its subsidiaries receive no
compensation for serving as directors or attending meetings.
Deferral Plan
SCANA has a plan pursuant to which directors may defer all
or a portion of their fees for services rendered and meeting
attendance. Interest is earned on the deferred amounts at a rate
set by the Performance Committee. During 1994 and currently, the
rate is set at the announced prime rate of Wachovia Bank of South
Carolina. Mr. Cassels and Mr. Rhodes were the only directors
participating in the plan during 1994. Mr. Cassels became a
participant in January 1994 and Mr. Rhodes in July 1987, and
interest credited to their deferral accounts during 1994 was
$1,009.92 and $12,741.17, respectively.
Endowment Plan
Each director participates in the Directors' Endowment Plan,
which provides for SCANA 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.
62
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
All shares of the Company's Common Stock are held,
beneficially and of record, by SCANA Corporation.
The table set forth below indicates the shares of SCANA's
Common Stock beneficially owned as of March 10, 1995 by each
director and nominee, each of the executive officers named in the
Summary Compensation Table on page 10, 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. Hayne Hipp 1,400
W. B. Bookhart, Jr. 7,362 B. D. Kenyon 6,629
W. T. Cassels, Jr. 1,000 F. C. McMaster 10,288
H. M. Chapman 3,000 Henry Ponder 5,498
J. B. Edwards 2,274 J. B. Rhodes 3,661
E. T. Freeman 2,090 R. W. Stedman 8,129
L. M. Gressette, Jr. 18,168 W. B. Timmerman 15,131
B. A. Hagood 1,162 E. C. Wall, Jr. 7,000
J. H. Young 5,395
All directors and executive officers as a group (19 persons) TOTAL 118,076
TOTAL PERCENT OF CLASS 0.2%
The information set forth above as to the security ownership has been
furnished to the Company by such persons.
______________
1 Includes shares owned by close relatives, the beneficial
ownership of which is disclaimed by the director or nominee, as
follows: Mr. Amick - 240; Mr. Bookhart - 2,062; Mr. Gressette -
530; Mr. Hagood - 163; and Mr. McMaster - 6,365.
Includes shares purchased through December 31, 1994, but not
thereafter, by the Trustee under the Stock Purchase-Savings Plan.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related
transactions, see Item 11, "Compensation Committee Interlocks and
Insider Participation."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
Financial Statements and Schedules
See Index to Consolidated Financial Statements and
Supplementary Data on page 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.
As permitted under Item 601(b)(4)(iii), instruments defining
the rights of holders of long-term debt of less than 10 percent
of the total consolidated assets of the Company and its
subsidiaries, have been omitted and the Company agrees to furnish
a copy of such instruments to the Commission upon request.
Reports on Form 8-K
None
63
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 14, 1995
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.
(i) Principal executive officer:
BY (SIGNATURE) s/L. M. Gressette, Jr.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board,
Chief Executive Officer and Director
DATE February 14, 1995
(ii) Principal financial officer:
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Chief Financial Officer
DATE February 14, 1995
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and Controller
DATE February 14, 1995
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 14, 1995
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 14, 1995
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 14, 1995
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 14, 1995
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 14, 1995
64
BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 14, 1995
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 14, 1995
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 14, 1995
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 14, 1995
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 14, 1995
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 14, 1995
BY (SIGNATURE) s/E. C. Wall, Jr.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 14, 1995
65