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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, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission File Number 1-3375
SOUTH CAROLINA ELECTRIC & GAS COMPANY
(Exact name of registrant as specified in its charter)
SOUTH CAROLINA 57-0248695
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)
1426 MAIN STREET, COLUMBIA, SOUTH CAROLINA 29201
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (803) 748-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
5% Cumulative Preferred Stock
par value $50 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
The Class is comprised of the following series of Cumulative
Preferred Stock, par value $50 per share or $100 per share,
having a periodic sinking fund:
9.40% Cumulative Preferred 8.72% Cumulative Preferred
Stock par value $50 per Stock par value $50
share per share
8.12% Cumulative Preferred 7.70% Cumulative Preferred
Stock par value $100 Stock par value $100
per share per share
Indicate by check mark whether the registrant: (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes x . No .
1
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
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 non-
affiliates of the registrant as of February 29, 1996 was zero.
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:
Indicate by check mark whether the registrant has filed all
documents and reports required to be filed by Section 12, 13 or
15(d) of the Securities Exchange Act of 1934 subsequent to the
distribution of securities under a plan confirmed by a court.
Yes No
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date.
As of February 29, 1996 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 .......................................... 19
Item 3. Legal Proceedings ................................... 21
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 21
PART II
Item 5. Market for Registrant's Common Stock
and Related Security Holder Matters ................ 21
Item 6. Selected Financial Data ............................. 22
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ...... 23
Item 8. Financial Statements and Supplementary Data ......... 30
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 55
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 55
Item 11. Executive Compensation .............................. 60
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 64
Item 13. Certain Relationships and Related Transactions ...... 65
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 65
SIGNATURES ........................................................ 66
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
Pipeline Corporation........ South Carolina Pipeline Corporation, an
affiliate
PRP......................... Potentially Responsible Party
PSA......................... The South Carolina Public Service Authority
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935,
as amended
SCANA....................... SCANA Corporation and its subsidiaries
Southern Natural............ Southern Natural Gas Company
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipeline Corporation
USEC........................ United States Enrichment Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams coal-fired, electric
generating station owned by GENCO
4
PART I
ITEM 1. BUSINESS
THE COMPANY
ORGANIZATION
The Company, a wholly owned subsidiary of SCANA, is a South
Carolina corporation organized in 1924 and has its principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Company had 3,721
full-time, permanent employees as of December 31, 1995 as
compared to 4,009 full-time, permanent employees as of December
31, 1994.
SCANA, a South Carolina corporation, was organized in 1984
and is a public utility holding company within the meaning of
PUHCA but is presently exempt from registration under such Act.
SCANA holds all of the issued and outstanding common stock of the
Company. (See Note 1A of Notes to Consolidated Financial
Statements.)
INDUSTRY SEGMENTS
The Company is a regulated public utility engaged in the
generation, transmission, distribution and sale of electricity
and in the purchase and sale, primarily at retail, of natural gas
in South Carolina. The Company also renders urban bus service in
the metropolitan areas of Columbia and Charleston, South
Carolina. The Company's business is subject to seasonal
fluctuations. Generally, sales of electricity are higher during
the summer and winter months because of air-conditioning and
heating requirements, and sales of natural gas are greater in the
winter months due to its use for heating requirements.
The Company's electric service area extends into 24 counties
covering more than 15,000 square miles in the central, southern
and southwestern portions of South Carolina. The service area
for natural gas encompasses all or part of 30 of the 46 counties
in South Carolina and covers more than 20,000 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, 1995, 1994 and 1993 is contained in Note 11 of
Notes to Consolidated Financial Statements and all such
information is incorporated herein by reference.
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less
regulatory protection. Future 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
operates 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. In January 1996 the PSC
approved (as discussed under "Capital Requirements and Financing
5
Program") the accelerated recovery of the Company's electric
regulatory assets and the shift of depreciation reserves from
transmission and distribution assets to nuclear production
assets. The Company believes that these actions as well as
numerous others that have been and will be taken demonstrate its
ability and commitment to succeed in the new operating
environment to come.
Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment
occur, the Company may no longer be qualified to apply this
accounting treatment and may be required to eliminate such
regulatory assets from its balance sheet. Such an event could
have a material adverse effect on the Company's results of
operations in the period the write-off is recorded. The Company
reported on its balance sheet at December 31, 1995 approximately
$116 million and $4 million of regulatory assets and
liabilities, respectively, excluding amounts related to net
accumulated deferred income tax assets of approximately $33
million.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The cash requirements of the Company arise primarily from
its operational needs and its construction program. The ability
of the Company to replace existing plant investments, as well as
to expand to meet future demand for electricity and gas, will
depend upon its ability to attract the necessary 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. On July 10, 1995,
the Company filed an application with the PSC for an increase in
retail electric rates. On January 9, 1996 the PSC issued an
order granting the Company an increase of 7.34% which will
produce additional revenues of approximately $67.5 million
annually. The increase will be implemented in two phases. The
first phase, an increase in revenues of approximately $59.5
million annually based on a test year, or 6.47%, commenced on
January 15, 1996. The second phase will be implemented in
January 1997 and will produce additional revenues of
approximately $8.0 million annually, or .87% more than current
rates. The PSC authorized a return on common equity of 12.0%.
The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over
a ten-year period. Additionally, the PSC approved accelerated
recovery of substantially all (excluding accumulated deferred
income taxes) of the Company's electric regulatory assets and the
transition obligation for postretirement benefits other than
pensions, changing the amortization periods to allow recovery by
the end of the year 2000. The Company's request to shift
approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved. The Company's future financial position and
results of operations will be affected by its ability to obtain
adequate and timely rate and other regulatory relief. (See
"Regulation.")
During 1996 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 77%, after payment of 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.
6
The Company's estimates of its cash requirements for
construction and nuclear fuel expenditures, which are subject to
continuing review and adjustment, for 1996 and the four-year
period 1997-2000 as now scheduled, are as follows:
Type of Facilities 1997-2000 1996
(Thousands of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $268,987 $ 49,036
Transmission. . . . . . . . . . . . . . . 92,502 17,976
Distribution. . . . . . . . . . . . . . . 319,092 64,227
Other . . . . . . . . . . . . . . . . . . 34,152 13,835
Nuclear Fuel. . . . . . . . . . . . . . . . 86,413 21,147
Gas . . . . . . . . . . . . . . . . . . . . 94,147 16,918
Common. . . . . . . . . . . . . . . . . . . 34,089 34,633
Other . . . . . . . . . . . . . . . . . . . 1,511 553
Total . . . . . . . . . . . . . . $930,893 $218,325
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program
for the periods 1996 and 1997-2000, shown in the above table,
include costs of the projects described below.
The Company entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina.
Construction of the plant started in November 1992. Commercial
operation began in January 1996. The cost of the Cope plant,
excluding AFC, is $410.9 million. In addition, the
transmission lines for interconnection with the Company's system
cost $22.5 million. Approximately $9.8 million of the amounts
included in the above table for 1996 relate to the completion of
the Cope plant.
During 1995 the Company expended approximately $15.9 million
as part of a program to extend the operating lives of certain
non-nuclear generating facilities. Additional improvements under
the program to be made during 1996 are estimated to cost
approximately $19.9 million.
Additional Capital Requirements
In addition to the Company's capital requirements for 1996
described in "Capital Requirements" above, approximately $21.2
million will be required for refunding and retiring outstanding
securities and obligations. For the years 1997-2000, the Company
has an aggregate of $292.8 million of long-term debt maturing
(including approximately $69.2 million for sinking fund
requirements, of which $68.7 million may be satisfied by deposit
and cancellation of bonds issued upon the basis of property
additions or bond retirement credits) and $9.8 million of
purchase or sinking fund requirements for preferred stock.
Actual 1996 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.
7
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 twelve
consecutive months out of the fifteen months prior to the month
of issuance are at least twice the annual interest requirements
on all Class A Bonds to be outstanding (Bond Ratio). For the
year ended December 31, 1995 the Bond Ratio was 3.97. The
issuance of additional Class A Bonds also is restricted to an
additional principal amount equal to (i) 60% of unfunded net
property additions (which unfunded net property additions totaled
approximately $162.3 million at December 31, 1995), (ii)
retirements of Class A Bonds (which retirement credits totaled
$64.8 million at December 31, 1995), (iii) and cash on deposit
with the Trustee.
The Company has placed a new bond indenture (New Mortgage)
dated April 1, 1993 covering substantially all of its electric
properties under which its future mortgage-backed debt (New
Bonds) will be issued. New Bonds are issued under the New
Mortgage on the basis of a like principal amount of Class A Bonds
issued under the Old Mortgage which have been deposited with
the Trustee of the New Mortgage (of which $185 million were
available for such purpose at December 31, 1995), until such time
as all presently outstanding Class A Bonds are retired.
Thereafter, New Bonds will be issuable on the basis of property
additions in a principal amount equal to 70% of the original cost
of electric and common plant properties (compared to 60% of value
for Class A Bonds under the Old Mortgage), cash deposited with
the Trustee, and retirement of New Bonds. New Bonds will be
issuable under the New Mortgage only if adjusted net earnings (as
therein defined) for twelve consecutive months out of the
eighteen months immediately preceding the month of issuance are
at least twice the annual interest requirements on all
outstanding bonds (including Class A Bonds) and New Bonds to be
outstanding (New Bond Ratio). For the year ended December 31,
1995 the New Bond Ratio was 5.31.
The following additional financing transaction has occurred
since December 31, 1994:
On April 12, 1995 the Company issued $100 million of First
Mortgage Bonds, 7 5/8% series due April 1, 2025 to repay
short-term borrowings.
Without the consent of at least a majority of the total
voting power of the Company's preferred stock, the Company may
not issue or assume any unsecured indebtedness if, after such
issue or assumption, the total principal amount of all such
unsecured indebtedness would exceed 10% of the aggregate
principal amount of all of the Company's secured indebtedness and
capital and surplus; provided, however, that no such consent
shall be required to enter into agreements for payment of
principal, interest and premium for securities issued for
pollution control purposes.
Pursuant to Section 204 of the Federal Power Act, the
Company must obtain the FERC authority to issue short-term debt.
The FERC has authorized the Company to issue up to $200 million
of unsecured promissory notes or commercial paper with maturity
dates of twelve months or less, but not later than December 31,
1997.
The Company had $165 million authorized and unused lines of
credit at December 31, 1995. In addition, Fuel Company has a
credit agreement for a maximum of $125 million with the full
amount available at December 31, 1995. The credit agreement
supports the issuance of short-term commercial paper for the
financing of nuclear and fossil fuels and sulfur dioxide emission
allowances. Fuel Company commercial paper outstanding at
December 31, 1995 was $76.8 million.
The Company's Restated Articles of Incorporation prohibit
issuance of additional shares of preferred stock without consent
of the preferred stockholders unless net earnings (as defined
therein) for the twelve consecutive months immediately preceding
the month of issuance are at least one and one-half times the
aggregate of all interest charges and preferred stock
dividend requirements (Preferred Stock Ratio). For the year
ended December 31, 1995 the Preferred Stock Ratio was 2.58.
8
The ratios of earnings to fixed charges (SEC Method) were
3.41, 3.46, 3.57, 2.73 and 3.32 for the years ended December 31,
1995, 1994, 1993, 1992 and 1991, respectively.
The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements for
the next twelve months and for the foreseeable future.
Fuel Financing Agreements
The Company has assigned to Fuel Company all of its rights
and interests in its various contracts relating to the
acquisition and ownership of nuclear and fossil fuels. To
finance nuclear and fossil fuels and sulfur dioxide emission
allowances, Fuel Company issues, from time to time, commercial
paper which is supported, up to $125 million, by an irrevocable
revolving credit agreement which expires July 31, 1998.
Accordingly, the amounts outstanding have been included in long-
term debt. This commercial paper and amounts outstanding under
the revolving credit agreement, if any, are guaranteed by the
Company.
At December 31, 1995 commercial paper outstanding was
approximately $76.8 million at a weighted average interest
rate of 5.76%. (See Notes 1N and 4 of Notes to Consolidated
Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 1995 residential sales of electricity accounted for 43%
of electric sales revenues; commercial sales 30%; industrial
sales 20%; sales for resale 4%; and all other 3%. KWH sales by
classification for the years ended December 31, 1995 and 1994 are
presented below:
Sales
KWH %
Classification 1995 1994 Change
(thousands)
Residential 5,726,815 5,311,139 7.83
Commercial 5,078,185 4,848,620 4.73
Industrial 5,210,368 5,161,717 0.94
Sale for resale 1,063,064 1,024,376 3.78
Other 506,806 494,030 2.59
Total Territorial 17,585,238 16,839,882 4.43
Interchange 195,591 171,046 14.35
Total 17,780,829 17,010,928 4.53
The Company furnishes electricity for resale to three
municipalities, four investor-owned utilities, two electric
cooperatives and one public power authority. Such sales for
resale accounted for 4% of total electric sales revenues in 1995.
During 1995 the Company recorded a net increase of 7,943
electric customers, increasing its total customers to 484,381.
9
The electric sales volume increased for the year ended
December 31, 1995 compared to the prior year as a result of
increased residential and commercial sales due to favorable
weather and customer growth. The all-time peak demand of 3,683
MW was set on August 14, 1995.
On August 8, 1995 the Company signed an agreement with the
DOE to lease the Savannah River Site's (SRS) power and steam
generation and transmission facilities. The agreement calls for
SRS to purchase all its electrical and a majority of its steam
requirements from the Company. The Company will lease (with an
option to renew) the power plant for ten years and the electrical
transmission lines for 40 years, with an option to refurbish the
facilities or build a new system.
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 portions of the nation. The Company, Virginia Power
Company, Duke Power Company, Carolina Power & Light Company,
Yadkin, Incorporated and PSA are members of the Virginia-
Carolinas Reliability Group, one of the several geographic
divisions within the Southeastern Electric Reliability Council.
This council provides for coordinated planning for reliability
among bulk power systems in the Southeast. The Company is also
interconnected with Georgia Power Company, Savannah Electric &
Power Company, Oglethorpe Power Corporation and Southeastern
Power Administration's Clark Hill Project.
Fuel Costs
The following table sets forth the average cost of nuclear
fuel and coal and the weighted average cost of all fuels
(including oil and natural gas) used by the Company and GENCO for
the years 1993-1995.
1995 1994 1993
Nuclear:
Per million BTU $ .48 $ .51 $ .47
Coal:
Company:
Per ton $40.01 $39.92 $39.95
Per million BTU 1.57 1.57 1.55
GENCO:
Per ton $42.21 $41.85 $41.64
Per million BTU 1.63 1.63 1.62
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.26 $ 1.39 $ 1.31
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.
10
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 1993-1995 and the
estimates for 1996 and 1997.
Percent of Total KWH Generated
Estimated Actual
1997 1996 1995 1994 1993
Coal 73% 71% 65% 76% 72%
Nuclear 24 24 27 17 23
Hydro 3 3 5 6 5
Natural Gas & Oil - 2 3 1 -
100% 100% 100% 100% 100%
Coal is used at all five of the Company's major fossil fuel-
fired plants and GENCO's Williams Station. Unit train deliveries
are used at all of these plants. On December 31, 1995 the
Company had approximately a 73-day supply of coal in inventory
and GENCO had approximately a 49-day supply.
The supply of coal is obtained through contracts and
purchases on the spot market. Spot market purchases are expected
to continue for coal requirements in excess of those provided by
the Company's existing contracts. Contracts for the purchase
of coal represent 91.5% of estimated requirements for 1996
(approximately 5.3 million tons, including requirements of
Williams Station).
The supply of contract coal is purchased from seven
suppliers located in eastern Kentucky and southwest Virginia.
Contract commitments, which expire at various times from 1997-
2003, approximate 4.85 million tons annually. Sulfur
restrictions on the contract coal range from .75% to 2%.
The Company believes that its operations are in substantial
compliance with all existing regulations relating to the
discharge of sulfur dioxide. The Company has not been advised by
officials of 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 has adequate supplies of uranium under contract
to manufacture nuclear fuel for Summer Station through 2005. The
following table summarizes all contract commitments for the
stages of nuclear fuel assemblies:
Commitment Contractor Regions(1) Term
Uranium Energy Resources
of Australia 9-13 1990-1997
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995
Enrichment USEC 12-18 1995-2005
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.
11
The Company has on-site spent nuclear fuel storage
capability until at least 2009 and expects to be able to expand
its storage capacity to accommodate the spent fuel output for the
life of the plant through rod consolidation, dry cask storage or
other technology as it becomes available. In addition, there is
sufficient on-site storage capacity over the life of Summer
Station to permit storage of the entire reactor core in the event
that complete unloading should become desirable or necessary for
any reason. (See "Nuclear Fuel Disposal" under "Environmental
Matters" for information regarding the contract with the DOE for
disposal of spent fuel.)
Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning costs
is referred to as COMReP (Cost of Money Reduction Plan). Under
this plan, funds collected through rates ($3.2 million in each of
1995 and 1994) are used to purchase insurance policies on the
lives of certain Company personnel. Through the purchase of
insurance contracts, the Company is able to take advantage of
income tax benefits and accrue earnings on the fund on a tax-
deferred basis at a rate higher than can be achieved using more
traditional funding approaches. Amounts for decommissioning
collected through electric rates, insurance proceeds, and
interest on proceeds less expenses are transferred by the Company
to an external trust fund in compliance with the financial
assurance requirements of the NRC. Management intends for the
fund, including earnings thereon, to provide for all eventual
decommissioning expenditures on an after-tax basis. The trust's
sources of decommissioning funds under the COMReP program include
investment components of life insurance policy proceeds, return
on investment and the cash transfers from the Company described
above. The Company records its liability for decommissioning
costs in deferred credits.
GAS OPERATIONS
Gas Sales
In 1995 residential sales accounted for 47% of gas sales
revenues; commercial sales 32%; industrial sales 21%.
Dekatherm sales by classification for the years ended December
31, 1995 and 1994 are presented below:
Sales
Dekatherms %
Classification 1995 1994 Change
Residential 12,333,769 11,531,558 7.0
Commercial 10,436,987 9,813,454 6.4
Industrial 13,467,687 10,938,713 23.1
Transportation gas 3,603,314 5,469,728 (34.1)
Total 39,841,757 37,753,453 5.5
During 1995 the Company recorded a net increase of 4,909 gas
customers, increasing its total customers to 243,342.
The Company purchases all of its natural gas from Pipeline
Corporation.
The demand for gas is affected by conservation, the weather,
the price relationship between gas and alternate fuels and other
factors.
12
The deregulation of natural gas prices at the wellhead and
the changes in the prices of natural gas that have occurred under
Federal regulation have resulted in the development of a spot
market for natural gas in the producing areas of the country.
Pipeline Corporation has been successful in purchasing lower cost
natural gas in the spot market and arranging for its
transportation to South Carolina.
On November 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which deregulated the markets for interstate sales of
natural gas by requiring that pipelines provide transportation
services that are equal in quality for all gas supplies whether
the customer purchases gas from the pipeline or another supplier.
The impact of this order on the Company will be primarily through
changes affecting its supplier, Pipeline Corporation.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for the purchase of alternate fuel vehicles on
Federal, state, municipal and private fleets. The Company
expects these requirements to develop business opportunities for
the sale of compressed natural gas as fuel for vehicles, but it
cannot predict the magnitude of this new market.
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts
with producers and marketers on a short-term basis at current
price indices and on a long-term basis for reliability assurance
at index prices plus a gas inventory charge. The gas is brought
to South Carolina through transportation agreements with both
Southern Natural and Transco, which expire at various times from
1996 to 2003. The volume of gas which Pipeline Corporation is
entitled to transport under these contracts on a firm basis is
shown below:
Maximum Daily
Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 184,974
Transco Firm Transportation 29,300
Total 214,274
Under a contract with Pipeline Corporation, the Company's
maximum daily contract demand is 224,270 dekatherms. The
contract allows the Company to receive amounts in excess of this
demand based on availability.
The average cost per MCF of natural gas purchased from
Pipeline Corporation was approximately $3.77 in 1995 compared to
$4.29 in 1994.
To meet the requirements of the Company and its other high
priority natural gas customers during periods of maximum demand,
Pipeline Corporation supplements its supplies of natural gas from
two LNG plants. The LNG plants are capable of storing the lique-
fied equivalent of 1,900,000 MCF of natural gas, of which
approximately 1,695,489 MCF were in storage at December 31, 1995.
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 of which 4,307,796 MCF
were in storage on December 31, 1995.
The Company believes that supplies under contract and
available for spot market purchase are adequate to meet existing
customer demands and to accommodate growth.
13
Curtailment Plans
The FERC has established allocation priorities applicable to
firm and interruptible capacities on interstate pipeline
companies to their customers which require Southern Natural and
Transco to allocate capacity to Pipeline Corporation. The FERC
allocation priorities are not applicable to deliveries by the
Company to its customers, which are governed by a separate
curtailment plan approved by the PSC.
REGULATION
General
The Company is subject to the jurisdiction of the PSC as to
retail electric, gas and transit rates, service, accounting,
issuance of securities (other than short-term promissory notes)
and other matters. The Company is subject to regulation under
the Federal Power Act, administered by the FERC and the DOE, in
the transmission of electric energy in interstate commerce and in
the sale of electric energy at wholesale for resale, as well as
with respect to licensed hydroelectric projects and certain other
matters, including accounting and the issuance of short-term
promissory notes.
In the opinion of the Company, it will be able to meet
successfully the challenges of the NEPA without any material
adverse impact on its results of operations, financial position
or business prospects.
Federal Energy Regulatory Commission
The Company is subject to regulation under the Federal Power
Act, administered by the FERC and the DOE, in the transmission of
electric energy in interstate commerce and in the sale of
electric energy at wholesale for resale, as well as with respect
to licensed hydroelectric projects and certain other matters
including accounting and the issuance of short-term promissory
notes. (See "Capital Requirements and Financing Program.")
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 2025
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, applications for new licenses for Neal Shoals and
Stevens Creek were filed with the FERC on December 30, 1991. No
competing applications were filed. The FERC issued a new 30-year
license for the Stevens Creek project on November 22, 1995. The
Neal Shoals license application is in the final stage of review.
The FERC has issued a Notice of Authorization for Continued
Project Operation for Neal Shoals until the FERC acts on the
Company's application for a new license.
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 is entitled to be paid its net investment in the
project, not to exceed fair value, plus severance damages.
14
The Company has filed an application with the FERC
requesting authorization to sell bulk power at market based
rates. The application also included proposed open access
transmission tariffs. (See "National Energy Policy Act of 1992
and FERC Order 636.")
Nuclear Regulatory Commission
The Company is subject to regulation by the NRC with respect
to the ownership and operation of Summer Station. The NRC's
jurisdiction encompasses broad supervisory and regulatory powers
over the construction and operation of nuclear reactors,
including matters of health and safety, antitrust considerations
and environmental impact. In addition, the Federal Emergency
Management Agency is responsible for the review, in conjunction
with the NRC, of certain aspects of emergency planning relating
to the operation of nuclear plants.
For the fourth time in the last five evaluations, Summer
Station received a category one rating from the Institute of
Nuclear Power Operations (INPO). The category one rating is the
highest given by INPO for a nuclear plant's overall operations.
National Energy Policy Act of 1992 and FERC Order 636
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 and does not
anticipate there to be any material adverse impact on the results
of its operations, its financial position or its business
prospects.
RATE MATTERS
The following table presents a summary of significant rate
activity for the years 1991-1995 based on test years:
REQUESTED GRANTED
Date of % % of
General Rate Application/ Amount Increase Date of Amount Increase
Applications Hearing (Millions) Requested Order (Millions) Granted
PSC
Electric
Retail 07/10/95 $ 76.7 8.4% 1/09/96 $67.5 88%
Retail 12/07/92 $ 72.0* 11.4% 6/07/93 $60.5 84%
Transit
Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
* As modified to reflect lowering of rate of return the Company was seeking.
15
On July 10, 1995, the Company filed an application with
the PSC for an increase in retail electric rates. On January 9,
1996 the PSC issued an order granting the Company an increase of
7.34% which will produce additional revenues of approximately
$67.5 million annually. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 million annually based on a test year, or
6.47%, commenced on January 15, 1996. The second phase will
be implemented in January 1997 and will produce additional
revenues of approximately $8.0 million annually, or .87% more
than current rates. The PSC authorized a return on common equity
of 12.0%. The PSC also approved establishment of a Storm Damage
Reserve Account capped at $50 million to be collected through
rates over a ten-year period. Additionally, the PSC approved
accelerated recovery of substantially all (excluding accumulated
deferred income taxes) of the Company's electric regulatory
assets and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods
to allow recovery by the end of the year 2000. The Company's
request to shift approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved.
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 actual
and projected site assessment and cleanup costs for the Company's
gas operations that had previously been deferred. In October
1995, as a result of the ongoing annual review, the PSC approved
the continued use of the billing surcharge. The balance
remaining to be recovered amounts to approximately $14.5 million.
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. On May 23, 1995 the Circuit Court ordered the case back
to the PSC for reconsideration of several issues including the
low-income rider program, routing changes, and the $.75 fare.
The Supreme Court declined to review an appeal of the Circuit
Court decision and dismissed the case. The PSC filed, along with
other intervenors, another Petition for Reconsideration, which
the Circuit Court denied. Procedural matters in this case are
yet to be resolved in the court.
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 1995 semiannual review of the fuel cost
component of electric rates, the PSC decreased the rate from
14.16 mills per KWH to 13.48 mills per KWH, a monthly decrease of
$.68 for an average customer using 1,000 KWH a month. For the
October 1995 review the PSC continued the rate of 13.48 mills per
KWH.
The Company's gas rate schedules and contracts include
mechanisms which allow it to recover from its customers changes
in the actual cost of gas. The Company's firm gas rates allow
for the recovery of a fixed cost of gas, based on projections, as
established by the PSC in annual gas cost and gas purchase
practice hearings. Any differences between actual and projected
gas costs are deferred and included when projecting gas costs
during the next annual gas cost recovery hearing.
In the October 1995 review the PSC decreased the base cost
of gas from 51.058 cents per therm to 43.081 cents per therm
which resulted in a monthly decrease of $7.98 (including
applicable taxes) based on an average of 100 therms per month on
a residential bill during the heating season.
16
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. Developments in these areas may require that
equipment and facilities be modified, supplemented or replaced.
The ultimate effect of these regulations and standards upon
existing and proposed operations cannot be forecast.
Capital Expenditures
In the years 1993 through 1995, capital expenditures for
environmental control amounted to approximately $90.0 million.
In addition, approximately $10.4 million, $8.8 million and $7.4
million of environmental control expenditures were made during
1995, 1994 and 1993, 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 capitalized expenditures are $10.1 million for 1996
and $138.8 million for the four-year period 1997 through 2000.
These expenditures are included in the Company's construction
program.
Air Quality Control
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by
the year 2000. These requirements are being phased in over two
periods. The first phase had a compliance date of January 1,
1995 and the second, January 1, 2000. The Company's facilities
did not require modifications to meet the requirements of Phase
I. The Company will most likely meet the Phase II requirements
through the burning of natural gas and/or lower sulfur coal in
its generating units and the purchase and use of sulfur dioxide
emission allowances. Low nitrogen oxide burners are being
installed to reduce nitrogen oxide emissions to the levels
required by Phase II. Air toxicity regulations for the electric
generating industry are likely to be promulgated around the year
2000.
The Company filed compliance plans related to Phase II
requirements with DHEC by December 31, 1995. The Company
currently estimates that air emissions control equipment will
require capital expenditures of $113 million over the 1996-2000
period to retrofit existing facilities, with increased operation
and maintenance cost of approximately $1 million per year. To
meet compliance requirements through the year 2005, the Company
anticipates total capital expenditures of approximately $150
million.
Water Quality Control
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a
national permit program. Discharge permits have been issued for
all and renewed for nearly all of the Company's and GENCO's
generating units. Concurrent with renewal of these permits the
permitting agency has implemented a more rigorous control
program. The Company has been developing compliance plans to
meet this program. Amendments to the Clean Water Act proposed in
Congress include several provisions which, if passed, could prove
costly to the Company. These include limitations to mixing
zones and the implementation of technology-based standards.
17
Superfund Act and Environmental Assessment Program
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, estimates are made of the cost, if any, to investigate
and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual
expenditures could differ significantly from original estimates.
Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations; such amounts
are deferred and are being amortized and recovered through rates
over a ten-year period for electric operations and an eight-year
period for gas operations. Deferred amounts totaled $18.0
million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates include, among other items, the costs
estimated to be associated with the matters discussed in the
following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company has maintained an active review of the sites to monitor
the nature and extent of the residual contamination.
In September 1992 the EPA notified the Company, the City of
Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the
Calhoun Park Area Site in Charleston, South Carolina. This site
originally encompassed approximately eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority List, but may
be added before cleanup is initiated. The PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigations process to
be compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope
of Work. Field work began in November 1993. 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 operations.
The Company has been listed as a PRP and has recorded
liabilities, which are not material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina. The Company has
participated in de minimis buy-outs for the Aqua-Tech
Environmental Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina. The Company expects
to have no further involvement with these two sites.
The Arkansas Department of Pollution Control and Ecology has
identified the Company as a PRP for clean-up of PCBs at an
abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from the Department has been received. The
Company believes that its identification as a PRP was in error,
and that the resolution of this issue will not have a material
effect on the Company's results of operations or financial
position.
18
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of
1991 directed the DHEC to promulgate regulations for the disposal
of industrial solid waste. DHEC has promulgated a proposal
regulation, which if adopted as a final regulation in its present
form, would significantly increase the Company's costs of
construction and operation of existing and future ash management
facilities.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 requires that the
United States government make available by 1998 a permanent
repository for high-level radioactive waste and spent nuclear
fuel and imposes a fee of 1.0 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 2009 and expects to be able to expand its storage capacity
over the life of Summer Station to accommodate the spent nuclear
fuel output for the life of the plant through rod consolidation,
dry cask storage or other technology as it becomes available.
The Act also imposes on utilities the primary responsibility for
storage of their spent nuclear fuel until the repository is
available.
OTHER MATTERS
With regard to the Company's insurance coverage for Summer
Station, reference is made to Note 10B of Notes to Consolidated
Financial Statements.
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.
19
ELECTRIC
The following table gives information with respect to the Company's
electric generating facilities.
Net Generating
Present Year Capability
Facility Fuel Capability Location In-Service (KW)(1)
Steam
Urquhart Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 430,000
Wateree Coal Eastover, SC 1970 700,000
Summer (2) Nuclear Parr, SC 1984 594,000
D-Area (3) Coal DOE Savannah
River Site, SC 1995 17,000
Cope (4) Coal Cope, SC 1996 385,000
Gas Turbines
Burton Gas/Oil Burton, SC 1961 28,500
Faber Place Gas Charleston, SC 1961 9,500
Hardeeville Oil Hardeeville, SC 1968 14,000
Canadys Gas/Oil Canadys, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (5) Gas/Oil Parr, SC 1970 60,000
Williams (6) Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000
Hydro
Neal Shoals Carlisle, SC 1905 5,000
Parr Shoals Parr, SC 1914 14,000
Stevens Creek Martinez, GA 1914 9,000
Columbia Columbia, SC 1927 10,000
Saluda Irmo, SC 1930 206,000
Pumped Storage
Fairfield Parr, SC 1978 512,000
Total (7) 3,722,000
(1) Summer rating.
(2) Represents the Company's two-thirds portion of the Summer
Station.
(3) This plant is operated under lease from the DOE and is
dispatched to DOE's Savannah River Site steam needs. "Net
Capacity Rating" for this plant is expected average hourly
output. The lease, which may be extended, expires on
October 1, 2005.
(4) Plant began commercial operation in January 1996.
(5) Two of the four Parr gas turbines are leased and have a net
capability of 34,000 KW. This lease expires on June 29,
1996. The Company has agreed to purchase the leased
turbines on the lease expiration date.
(6) The two gas turbines at Williams are leased and have a net
capability of 49,000 KW. This lease expires on June 29,
1997.
(7) Excludes Williams Station.
20
The Company owns 429 substations having an aggregate
transformer capacity of 19,577,868 KVA. The transmission system
consists of 3,090 miles of lines and the distribution system
consists of 15,596 pole miles of overhead lines and 3,191 trench
miles of underground lines.
GAS
Natural Gas
The Company's gas system consists of approximately 6,833
miles of three-inch equivalent distribution pipelines and
approximately 11,265 miles of distribution mains and related
service facilities.
Propane
The Company has propane air peak shaving facilities which
can supplement the supply of natural gas by gasifying propane to
yield the equivalent of 102,000 MCF per day of natural gas.
These facilities can store the equivalent of 430,405 MCF of
natural gas.
TRANSIT
The Company owns 98 motor coaches which operate on a route
system of 286 miles.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1.,
"BUSINESS - RATE MATTERS" and "BUSINESS - ENVIRONMENTAL MATTERS -
Superfund Act and Environmental Assessment Program" and Note 10
of Notes to Consolidated Financial Statements appearing in Item
8., "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON 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 1995 and
1994 the Company paid $116.7 million and $115.1 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, 1995
approximately $14.5 million of retained earnings were restricted
as to payment of cash dividends on common stock.
21
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1995 1994 1993 1992 1991
Statement of Income Data (Thousands of Dollars except statistics)
Operating Revenues $1,211,087 $1,181,274 $1,118,433 $ 994,381 $1,022,342
Operating Income 255,854 230,418 219,319 182,267 196,706
Other Income 9,553 7,271 6,585 3,006 3,283
Net Income 169,185 152,043 145,968 102,163 122,836
Earnings Available for Common Stock 163,498 146,088 139,751 95,689 116,130
Balance Sheet Data
Utility Plant, Net $3,157,657 $2,998,132 $2,687,193 $2,503,201 $2,380,761
Total Assets 3,802,433 3,587,091 3,189,939 2,890,953 2,748,580
Capitalization:
Common equity 1,315,072 1,133,432 1,051,334 963,741 840,505
Preferred stock (Not subject
to purchase or sinking funds) 26,027 26,027 26,027 26,027 26,027
Preferred stock, Net (Subject to
purchase or sinking funds) 46,243 49,528 52,840 56,154 59,469
Long-term debt, Net 1,279,379 1,231,191 1,097,043 945,964 993,674
Total Capitalization $2,666,721 $2,440,178 $2,227,244 $1,991,886 $1,919,675
Other Statistics
Electric:
Customers (Year-End) 484,381 476,438 468,901 461,928 453,687
Territorial Sales (Million KWH) 17,585 16,840 16,889 15,801 15,702
Residential:
Average annual use per customer (KWH) 13,859 13,048 14,077 13,037 13,246
Average annual rate per KWH $.0747 $.0743 $.0707 $.0695 $.0700
Gas:
Customers (Year-End) 243,342 238,433 221,278 218,582 214,485
Sales (Thousand Therms) 362,384 322,837 267,335 256,495 247,483
Residential:
Average annual use per customer (Therms) 570 538 606 577 522
Average annual rate per therm $.82 $.84 $.76 $.74 $.77
22
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. 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, future prices 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 operates
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. In January 1996 the PSC approved (as discussed
under "Liquidity and Capital Resources") the accelerated recovery
of the Company's electric regulatory assets and the shift of
depreciation reserves from transmission and distribution assets
to nuclear production assets. The Company believes that these
actions as well as numerous others that have been and will be
taken demonstrate its ability and commitment to succeed in the
new operating environment to come.
Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment
occur, the Company may no longer be eligible to apply this
accounting treatment and may be required to eliminate such
regulatory assets from its balance sheet. Such an event could
have a material adverse effect on the Company's results of
operations in the period the write-off is recorded. The Company
reported approximately $116 million and $4 million of regulatory
assets and liabilities, respectively, excluding amounts related
to net accumulated deferred income tax assets of approximately
$33 million, on its balance sheet at December 31, 1995.
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 and other regulatory 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. Construction of the plant started in November
1992. Commercial operation began in January 1996. The estimated
cost of the Cope plant, excluding AFC, is $410.9 million. In
addition, the transmission lines for interconnection with the
Company's system are expected to cost $22.5 million.
On July 10, 1995 the Company filed an application with the
PSC for an increase in retail electric rates. On January 9, 1996
the PSC issued an order granting the Company an increase of 7.34%
which will produce additional revenues of approximately $67.5
million annually. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 annually based on a test year, or 6.47%,
commenced on January 15, 1996. The second phase will be
implemented in January 1997 and will produce additional revenues
of approximately $8.0 million annually, or .87% more than current
rates. The PSC authorized a return on common equity of 12.0%.
The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over
a ten-year period. Additionally, the PSC approved accelerated
recovery of substantially all of the Company's electric
regulatory assets (excluding accumulated deferred income taxes)
and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods
to allow recovery by the end of the year 2000. The Company's
request to shift approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved.
23
The estimated primary cash requirements for 1996, excluding
requirements for fuel liabilities and short-term borrowings,
(including notes payable to affiliated companies), and the actual
primary cash requirements for 1995 are as follows:
1996 1995
(Thousands of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $197,179 $250,870
Nuclear fuel expenditures 21,147 21,045
Maturing obligations, redemptions and
sinking and purchase fund requirements 21,197 15,812
Total $239,523 $287,727
Approximately 45% of total cash requirements (after payment
of dividends) was provided from internal sources in 1995 as
compared to 22% in 1994.
The Company's First and Refunding Mortgage Bond Indenture,
dated April 1, 1945 (Old Mortgage), contains provisions
prohibiting the issuance of additional bonds thereunder (Class A
Bonds) unless net earnings (as therein defined) for twelve
consecutive months out of the fifteen months prior to the month
of issuance are at least twice the annual interest requirements
on all Class A Bonds to be outstanding (Bond Ratio). For the
year ended December 31, 1995 the Bond Ratio was 3.97. The
issuance of additional Class A Bonds also is restricted to an
additional principal amount equal to (i) 60% of unfunded net
property additions (which unfunded net property additions totaled
approximately $162.3 million at December 31, 1995), (ii)
retirements of Class A Bonds (which retirement credits totaled
$64.8 million at December 31, 1995), (iii) and cash on deposit
with the Trustee.
The Company has a new indenture (New Mortgage) dated April 1,
1993 covering substantially all of its electric properties under
which its future mortgage-backed debt (New Bonds) will be issued.
New Bonds are issued under the New Mortgage on the basis of a
like principal amount of Class A Bonds issued under the Old
Mortgage which have been deposited with the Trustee of the
New Mortgage (of which $185 million were available for such
purpose as of December 31, 1995), until such time as all
presently outstanding Class A Bonds are retired. Thereafter, New
Bonds will be issuable on the basis of property additions in a
principal amount equal to 70% of the original cost of electric
and common plant properties (compared to 60% of value for Class A
Bonds under the Old Mortgage), cash deposited with the Trustee,
and retirement of New Bonds. New Bonds will be issuable under
the New Mortgage only if adjusted net earnings (as therein
defined) for twelve consecutive months out of the eighteen months
immediately preceding the month of issuance are at least twice
the annual interest requirements on all outstanding bonds
(including Class A Bonds) and New Bonds to be outstanding (New
Bond Ratio). For the year ended December 31, 1995 the New Bond
Ratio was 5.31.
The following financing transaction has occurred since
December 31, 1994:
On April 12, 1995 the Company issued $100 million of
First Mortgage Bonds, 7 5/8% series due April 1, 2025
to repay short-term borrowings.
Without the consent of at least a majority of the total
voting power of the Company's preferred stock, the Company may
not issue or assume any unsecured indebtedness if, after such
issue or assumption, the total principal amount of all such
unsecured indebtedness would exceed 10% of the aggregate
principal amount of all of the Company's secured indebtedness and
capital and surplus; provided, however, that no such consent
shall be required to enter into agreements for payment of
principal, interest and premium for securities issued for
pollution control purposes.
Pursuant to Section 204 of the Federal Power Act, the
Company must obtain the FERC authority to issue short-term
indebtedness. The FERC ha authorized the Company to issue up to
$200 million of unsecured promissory notes or commercial paper
with maturity dates of twelve months or less, but not later than
December 31, 1997.
The Company had $165 million authorized and unused lines of
credit at December 31, 1995. In addition, the Company has a
credit agreement for a maximum of $125 million with the full
amount available at December 31, 1995. The credit agreement
supports the issuance of short-term commercial paper for the
financing of nuclear and fossil fuels and sulfur dioxide emission
allowances. Fuel Company commercial paper outstanding at
December 31, 1995 was $76.8 million.
24
The Company's Restated Articles of Incorporation prohibit
issuance of additional shares of preferred stock without consent
of the preferred stockholders unless net earnings (as defined
therein) for the twelve consecutive months immediately preceding
the month of issuance are at least one and one-half times the
aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended
December 31, 1995 the Preferred Stock Ratio was 2.58.
The Company anticipates that its 1996 cash requirements of
$378.9 million will be met through internally generated funds
(approximately 77%, after payment of dividends), the sales of
additional equity securities, additional equity contributions
from SCANA and the incurrence of additional short-term and long-
term indebtedness. The timing and amount of such financing will
depend upon market conditions and other factors. Actual 1996
expenditures may vary from the estimates set forth above due to
factors such as inflation and economic conditions, regulation and
legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.
The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements for
the next twelve months and for the foreseeable future.
Environmental Matters
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by
the year 2000. These requirements are being phased in over two
periods. The first phase had a compliance date of January 1,
1995 and the second, January 1, 2000. The Company's facilities
did not require modifications to meet the requirements of Phase
I. The Company will most likely meet the Phase II requirements
through the burning of natural gas and/or lower sulfur coal in
its generating units and the purchase and use of sulfur dioxide
emission allowances. Low nitrogen oxide burners are being
installed to reduce nitrogen oxide emissions to the levels
required by Phase II. Air toxicity regulations for the electric
generating industry are likely to be promulgated around the year
2000.
By December 31, 1995 the Company had filed compliance plans
related to Phase II requirements with DHEC. The Company
currently estimates that air emissions control equipment will
require capital expenditures of $113 million over the 1996-2000
period to retrofit existing facilities, with increased operation
and maintenance cost of approximately $1 million per year. To
meet compliance requirements through the year 2005, the Company
anticipates total capital expenditures of approximately $150
million.
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a
national permit program. Discharge permits have been issued for
all and renewed for nearly all of SCE&G'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 for this program.
Amendments to the Clean Water Act proposed in Congress include
several provisions which, if passed, 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 directed DHEC to promulgate regulations for the disposal of
industrial solid waste. DHEC has promulgated a proposed
regulation which, if adopted as a final regulation in its present
form, would significantly increase the Company's and GENCO's
costs of construction and operation of existing and future ash
management facilities.
25
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, estimates are made of the cost, if any, to investigate
and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual
expenditures could differ significantly from original estimates.
Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations; such amounts
are deferred and are being amortized and recovered through rates
over a ten-year period for electric operations and an eight-
year period for gas operations. Deferred amounts totaled
$18.0 million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates include, among other items, the costs
associated with the matters discussed in the following
paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.
In September 1992 the EPA notified the Company, the City of
Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the
Calhoun Park Area Site in Charleston, South Carolina. This site
originally encompassed approximately eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority List, but may
be added before cleanup is initiated. The PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigation process to be
compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a
Remedial Investigation/Feasibility Study and a corresponding
Scope of Work. Field work began in November 1993. The Company
is also working with the City of Charleston to investigate
potential contamination from the manufactured gas plant which may
have migrated to the City's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to
be responsible for a $43.5 million increase in costs of the
aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes it has meritorious defenses against this claim and does
not expect its resolution to have a material impact on its
financial position or results of operations.
Regulatory Matters
The Company filed for electric rate relief in 1995 to
encompass primarily the remaining costs of completing the Cope
Generating Station. As discussed under "Liquidity and Capital
Resources," the PSC issued an order on January 9, 1996 increasing
electric retail rates.
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 and does not
anticipate there to be any material adverse impact on the results
of its operations, its financial position or its business
prospects.
26
Statements of Financial Accounting Standards To Be Adopted
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." The provisions of the Statement, which will be
implemented by the Company for the fiscal year beginning January
1, 1996, require the recognition of a loss in the income
statement and related disclosures whenever events or changes in
circumstances indicate that the carrying amount of a long-lived
asset may not be recoverable. The Company does not believe that
adoption of the provisions of the Statement will have a material
impact on its results of operations or financial position.
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-
Based Compensation," which will be implemented by the Company on
January 1, 1996. The Company does not believe that adoption of
the provisions of the Statement will have a material impact on
its results of operations or financial position.
RESULTS OF OPERATIONS
Net Income
Net income and the percent increase (decrease) from the
previous year for the years 1995, 1994 and 1993 were as follows:
1995 1994 1993
Net income $169,185 $152,043 $145,968
Percent increase (decrease) in net
income 11.27% 4.16% 42.9%
1995 Net income increased for the year primarily due to
increases in electric and gas margins and lower operating
and maintenance expenses which more than offset increases
in fixed costs.
1994 Net income increased for the year primarily due to an
increase in the electric margin which more than
offset increases in operating expenses.
The Company's financial statements include an allowance for
funds used during construction (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 7.9 % of income before income taxes in 1995, 6.3%
in 1994 and 5.6% in 1993.
27
Electric Operations
Electric sales margins for 1995, 1994 and 1993 were as
follows:
1995 1994 1993
(Millions of Dollars)
Electric revenues $1,006.6 $974.3 $940.2
(Provision) for rate refunds - 1.2 0.3
Net Electric operating revenues 1,006.6 975.5 940.5
Less: Fuel used in electric generation 177.6 176.6 164.2
Purchased power 98.2 112.9 111.1
Margin $ 730.8 $686.0 $665.2
1995 The electric sales margin increased over the prior
year primarily as a result of the combined impact of
warmer weather in the third quarter of 1995, colder
weather in the fourth quarter of 1995 and the base rate
increase received by the Company in mid-1994. These
factors more than offset the negative impact of milder
weather experienced during the first half of 1995. An
increase of 7,943 electric customers to 484,381 total
customers contributed to an all-time peak demand record of
3,683 MW set on August 14, 1995.
1994 The electric sales margin increased over the prior
year primarily as a result of an increase in retail
electric rates phased in over a two-year period beginning
in June 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.
Increases (decreases) from the prior year in megawatt hour (MWH) sales
volume by classes were as follows:
Classification 1995 1994
Residential 415,676 (339,620)
Commercial 229,565 4,198
Industrial 48,651 274,467
Sale for Resale (excluding interchange) 38,688 18,408
Other 12,776 (6,907)
Total territorial 745,356 (49,454)
Interchange 24,545 (27,013)
Total 769,901 (76,467)
Gas Operations
Gas sales margins for 1995, 1994 and 1993 were as follows:
1995 1994 1993
(Millions of Dollars)
Gas operating revenues $200.6 $201.7 $174.0
Less: Gas purchased for resale 125.0 127.8 107.7
Margin $ 75.6 $ 73.9 $ 66.3
1995 The gas sales margin increased over the prior year
primarily as a result of increases in interruptible gas
sales.
1994 The gas sales margin increased over the prior year
primarily as a result of increases in interruptible
gas sales.
28
Increases (decreases) from the prior year in dekatherm (DT)
sales volume by classes, including transportation gas, were as
follows:
Classification 1995 1994
Residential 802,211 (477,886)
Commercial 623,533 970,726
Industrial 2,528,974 5,057,404
Transportation gas (1,866,414) (1,524,089)
Total 2,088,304 4,026,155
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including
taxes, were as follows:
Classification 1995 1994
(Millions of Dollars)
Other operation and maintenance $(7.8) $ 3.9
Depreciation and amortization 10.6 5.7
Income taxes 12.9 2.8
Other taxes 5.1 5.0
Total $20.8 $17.4
1995 Other operation and maintenance expenses decreased
primarily as a result of lower pension costs and lower costs
at electric generating stations. The increase in
depreciation and amortization expense primarily is
attributable to additions to plant-in-service and the
expensing of software costs. The increase in income tax
expense corresponds to the increase in operating income. The
increase in other taxes reflects higher property taxes
resulting from higher millages and assessments partially
offset by lower payroll taxes resulting from early
retirements of employees.
1994 Other operation and maintenance expenses increased
primarily due to an increase in the costs of postretirement
benefits other than pensions. These costs are accrued in
accordance with Financial Accounting Standards Board
Statement No. 106. (See Note 1K of Notes to Consolidated
Financial Statements.) The increase in depreciation and
amortization expenses is attributable to property additions
and to increases in depreciation rates. The increase in
other taxes reflects an increase in property taxes of
approximately $5 million.
Interest Expense
Increases (decreases) in interest expense were as follows:
Classification 1995 1994
(Millions of Dollars)
Interest on long-term debt, net $11.0 $8.0
Other interest expense 4.1 (.6)
Total $15.1 $7.4
1995 The increase in interest expense, excluding the debt
component of AFC, is due primarily to the issuance of
additional debt including commercial paper during the latter
part of 1994 and early 1995.
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.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report....................................... 31
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1995 and 1994... 32
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1995, 1994 and 1993............. 34
Consolidated Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993............................. 35
Consolidated Statements of Capitalization as of
December 31, 1995 and 1994................................... 36
Notes to Consolidated Financial Statements..................... 38
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.
30
INDEPENDENT AUDITOR'S REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and
Statements of Capitalization of South Carolina Electric & Gas
Company (Company) as of December 31, 1995 and 1994 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, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company at December 31, 1995 and 1994 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1995 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 1996
31
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1995 1994
(Thousands of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $3,277,530 $3,165,391
Gas 320,847 307,929
Transit 3,768 3,785
Common 91,616 77,327
Total 3,693,761 3,554,432
Less accumulated depreciation and amortization 1,196,279 1,171,758
Total 2,497,482 2,382,674
Construction work in progress 613,683 571,867
Nuclear fuel, net of accumulated amortization 46,492 43,591
Utility Plant, Net 3,157,657 2,998,132
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 11,603 11,931
Current Assets:
Cash and temporary cash investments (Note 8) 6,798 346
Receivables - customer and other 154,816 127,679
Receivables - affiliated companies (Note 1) 7,132 18,121
Inventories (At average cost):
Fuel (Notes 1, 3 and 4) 35,812 31,310
Materials and supplies 43,583 43,228
Prepayments 10,158 14,389
Accumulated deferred income taxes 19,420 17,931
Total Current Assets 277,719 253,004
Deferred Debits:
Emission allowances 28,514 19,409
Unamortized debt expense 11,445 11,690
Unamortized deferred return on plant investment (Notes 1 and 2) 6,369 10,614
Nuclear plant decommissioning fund (Note 1) 36,070 30,383
Other (Note 1) 273,056 251,928
Total Deferred Debits 355,454 324,024
Total $3,802,433 $3,587,091
32
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1995 1994
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment:
Common equity (Note 5) $1,315,072 $1,133,432
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,341,099 1,159,459
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 46,243 49,528
Long-Term Debt, Net (Notes 3, 4 and 8) 1,279,379 1,231,191
Total Capitalization 2,666,721 2,440,178
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 80,500 100,000
Notes payable - affiliated companies - 19,409
Current portion of long-term debt (Note 3) 36,033 33,042
Current portion of preferred stock (Note 6) 2,439 2,418
Accounts payable 71,731 61,466
Accounts payable - affiliated companies (Notes 1 and 3) 26,212 33,357
Customer deposits 12,518 12,668
Taxes accrued 64,008 46,646
Interest accrued 21,626 21,534
Dividends declared 33,126 28,489
Other 12,507 15,525
Total Current Liabilities 360,700 374,554
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 488,310 503,723
Accumulated deferred investment tax credits (Notes 1 and 7) 78,316 81,546
Accumulated reserve for nuclear plant decommissioning (Note 1) 36,070 30,383
Other (Note 1) 172,316 156,707
Total Deferred Credits 775,012 772,359
Commitments and Contingencies (Note 10) - -
Total $3,802,433 $3,587,091
See Notes to Consolidated Financial Statements.
33
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1995 1994 1993
(Thousands of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $1,006,566 $ 975,526 $ 940,547
Gas 200,632 201,746 174,035
Transit 3,889 4,002 3,851
Total Operating Revenues 1,211,087 1,181,274 1,118,433
Operating Expenses:
Fuel used in electric generation 177,579 176,581 164,187
Purchased power (including affiliated
purchases)(Note 1) 98,231 112,900 111,111
Gas purchased from affiliate for resale (Note 1) 125,032 127,846 107,722
Other operation 211,318 214,344 207,126
Maintenance 53,071 57,801 61,107
Depreciation and amortization (Note 1) 117,584 106,952 101,220
Income taxes (Notes 1 and 7) 96,956 84,066 81,280
Other taxes (Note 12) 75,462 70,366 65,361
Total Operating Expenses 955,233 950,856 899,114
Operating Income 255,854 230,418 219,319
Other Income (Note 1):
Allowance for equity funds used during construction 9,499 7,989 7,496
Other income (loss), net of income taxes 54 (718) (911)
Total Other Income 9,553 7,271 6,585
Income Before Interest Charges 265,407 237,689 225,904
Interest Charges (Credits):
Interest on long-term debt, net 98,361 87,361 79,410
Other interest expense (Notes 1 and 3) 9,324 5,189 5,812
Allowance for borrowed funds used
during construction (Note 1) (11,463) (6,904) (5,286)
Total Interest Charges, Net 96,222 85,646 79,936
Net Income 169,185 152,043 145,968
Preferred Stock Cash Dividends (At stated rates) (5,687) (5,955) (6,217)
Earnings Available for Common Stock 163,498 146,088 139,751
Retained Earnings at Beginning of Year 324,101 291,713 262,262
Common Stock Cash Dividends Declared (Note 5) (121,363) (113,700) (110,300)
Retained Earnings at End of Year $ 366,236 $ 324,101 $ 291,713
See Notes to Consolidated Financial Statements.
34
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995 1994 1993
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $169,185 $152,043 $145,968
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 117,839 107,103 101,370
Amortization of nuclear fuel 20,017 13,487 18,156
Deferred income taxes, net (17,632) 13,133 56,982
Deferred investment tax credits, net (3,230) (2,901) (3,245)
Net regulatory asset arising from adoption of SFAS No. 109 13,560 (1,985) (40,398)
Allowance for funds used during construction (20,962) (14,893) (12,782)
Unamortized loss on reacquired debt (3,325) (129) (17,094)
Early retirements (24,823) (7,086) (11,840)
Nuclear refueling accrual 6,957 (4,881) (6,086)
Over (under) collections, fuel adjustment clause 18,986 (17,965) (13,728)
Emission allowances (9,105) (19,409) -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (16,148) (26,260) (27,920)
(Increase) decrease in inventories (4,857) 26 1,401
Increase (decrease) in accounts payable 3,120 (430) 16,757
Increase (decrease) in estimated rate
refunds and related interest - (2,509) (15,302)
Increase (decrease) in taxes accrued 17,362 6,681 (11,162)
Increase (decrease) in interest accrued 92 3,770 (8,669)
Other, net (14,623) 14,106 8,002
Net Cash Provided From Operating Activities 252,413 211,901 180,410
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, net of AFC (271,804) (406,054) (287,838)
Nonutility property and investments (111) (287) (248)
Transfer of assets from SCANA - 6,285 -
Net Cash Used For Investing Activities (271,915) (400,056) (288,086)
Cash Flows From Financing Activities:
Proceeds:
Issuance of notes payable - affiliated company - 19,409 -
Issuance of mortgage bonds 99,583 99,207 592,884
Issuance of pollution control bonds - 30,000 -
Equity contributions from parent 139,505 43,426 58,142
Other long-term debt 2,543 11,200 2,562
Repayments:
Notes payable - affiliated company (19,409) - -
Mortgage bonds (64,779) - (430,000)
Other long-term debt (12,548) (1,662) (405)
Preferred stock (3,264) (3,398) (3,295)
Dividend Payments:
Common stock (116,663) (115,100) (108,641)
Preferred stock (5,750) (6,048) (6,247)
Short-term borrowings, net (19,500) 98,989 978
Fuel and emission allowance financings, net 26,236 13,844 (18,948)
Advances - affiliated companies, net - (1,559) (3,463)
Net Cash Provided From Financing Activities 25,954 188,308 83,567
Net Increase (Decrease) in Cash and Temporary Cash Investments 6,452 153 (24,109)
Cash and Temporary Cash Investments, January 1 346 193 24,302
Cash and Temporary Cash Investments, December 31 $ 6,798 $ 346 $ 193
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $11,463, $6,904 and $5,286) $105,537 $ 87,255 $ 92,367
- Income taxes 95,827 77,295 79,612
Noncash Financing Activities:
Department of Energy decontamination and decommissioning
fund obligation - - 4,965
See Notes to Consolidated Financial Statements.
35
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1995 1994
Common Equity (Note 5): (Thousands of Dollars)
Common Stock, $4.50 par value, authorized 50,000,000 shares; issued
and outstanding, 40,296,147 shares $ 181,333 $181,333
Premium on common stock 395,072 395,072
Other paid-in capital 377,822 238,369
Capital stock expense (5,391) (5,443)
Retained earnings 366,236 324,101
Total Common Equity 1,315,072 49% 1,133,432 47%
Cumulative Preferred Stock (Not subject to purchase or sinking funds):
$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
$100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767
$50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260
Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1%
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8):
$100 Par Value - Authorized 1,550,000 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
7.70% 86,965 89,984 101.00 - 101.00 8,696 8,998
8.12% 123,045 126,835 102.03 - 102.03 12,305 12,684
Total 210,010 216,819
$50 Par Value - Authorized 1,614,405 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
4.50% 17,519 19,088 51.00 - 51.00 876 954
4.60% 834 2,334 50.50 - 50.50 42 117
4.60%(A) 26,052 28,052 51.00 - 51.00 1,303 1,403
4.60%(B) 74,800 78,200 50.50 - 50.50 3,740 3,910
5.125% 72,000 73,000 51.00 - 51.00 3,600 3,650
6.00% 83,200 86,400 50.50 - 50.50 4,160 4,320
8.72% 95,985 127,956 51.00 12-31-98 50.00 4,799 6,398
9.40% 183,219 190,245 51.175 - 51.175 9,161 9,512
Total 553,609 605,275
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1995 and 1994
Total Preferred Stock (Subject to purchase or sinking funds) 48,682 51,946
Less: Current portion, including sinking fund requirements 2,439 2,418
Total Preferred Stock, Net (Subject to purchase or sinking funds) 46,243 2% 49,528 2%
36
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1995 1994
(Thousands of Dollars)
Long-Term Debt (Notes 3, 4 and 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100,000 100,000
6 1/4% 2003 100,000 100,000
7.70% 2004 100,000 100,000
7 1/8% 2013 150,000 150,000
7 1/2% 2023 150,000 150,000
7 5/8% 2023 100,000 100,000
7 5/8% 2025 100,000 -
First and Refunding Mortgage Bonds:
Year of
Series Maturity
4 7/8% 1995 - 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
7 1/4% 2002 30,000 30,000
9% 2006 130,771 145,000
8 7/8% 2021 120,450 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,560 6,660
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365
Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 30,000
Department of Energy Decontamination and Decommissioning Obligation 3,560 3,922
Commercial Paper 76,830 61,794
Other 3,993 3,294
Total Long-Term Debt 1,319,649 1,269,155
Less: Current maturities, including sinking fund requirements 36,033 33,042
Unamortized discount 4,237 4,922
Total Long-Term Debt, Net 1,279,379 48% 1,231,191 50%
Total Capitalization $2,666,721 100% $2,440,178 100%
See Notes to Consolidated Financial Statements.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
The Company, a public utility, is a South Carolina
corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation (SCANA), a South Carolina holding company. The
Company, through wholly owned subsidiaries is predominately
engaged in the generation and sale of electricity to wholesale
and retail customers in South Carolina and in the purchase, sale
and transportation of natural gas to retail customers in South
Carolina.
The accompanying Consolidated Financial Statements include
the accounts of the Company and South Carolina Fuel Company, Inc.
(Fuel Company). (See Note 1N.) Intercompany balances and
transactions between the Company and Fuel Company have been
eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain
affiliates to purchase gas for resale to its distribution
customers and to purchase electric energy. The Company purchases
all of its natural gas requirements from Pipeline Corporation and
at December 31, 1995 and 1994 the Company had approximately $17.5
million and $16.3 million, respectively, payable to Pipeline
Corporation for such gas purchases. The Company purchases all of
the electric generation of Williams Station, which is owned by
GENCO, under a unit power sales agreement. At December 31, 1995
and 1994 the Company had approximately $8.2 million and $8.8
million, respectively, payable to GENCO for unit power purchases.
Such unit power purchases, which are included in "Purchased
power," amounted to approximately $83.5 million, $92.8 million
and $98.1 million in 1995, 1994 and 1993, respectively.
Total interest income, based on market interest rates,
associated with the Company's advances to affiliated companies
was approximately $174,000, $5,000 and $143,000 in 1995, 1994 and
1993, respectively.
Included in "Other interest expense" for 1995, 1994 and 1993
is approximately $114,000, $279,000 and $29,000, respectively,
relating to advances from affiliated companies. Intercompany
interest is calculated at market rates.
B. Basis of Accounting
The Company prepares its financial statements in accordance
with the provisions of Statement of Financial Accounting
Standards No. 71 (SFAS 71), "Accounting for the Effects of
Certain Types of Regulations." The accounting standard allows
cost-based rate-regulated utilities, such as the Company, to
recognize in their financial statements revenues and expenses in
different time periods than do enterprises that are not rate-
regulated. As a result the Company has recorded, as of
December 31, 1995, approximately $116 million and $4 million of
regulatory assets and liabilities, respectively, excluding net
accumulated deferred income tax assets of approximately $33
million. As discussed in Note 2A, the PSC has approved
accelerated recovery of substantially all of the Company's
electric regulatory assets (approximately $84.8 million). In the
future, as a result of deregulation or other changes in the
regulatory environment, the Company may no longer meet the
criteria for continued application of SFAS 71 and would be
required to write off its regulatory assets and liabilities.
Such an event could have a material adverse effect on the
Company's results of operations in the period the write-off is
recorded.
C. System of Accounts
The accounting records of the Company are maintained in
accordance with the Uniform System of Accounts prescribed by the
FERC and as adopted by the PSC.
38
D. Utility Plant
Utility plant is stated substantially at original cost. The
costs of additions, renewals and betterments to utility plant,
including direct labor, material and indirect charges for
engineering, supervision and an allowance for funds used during
construction, are added to utility plant accounts. The original
cost of utility property retired or otherwise disposed of is
removed from utility plant accounts and generally charged, along
with the cost of removal, less salvage, to accumulated
depreciation. The costs of repairs, replacements and renewals of
items of property determined to be less than a unit of property
are charged to maintenance expense.
The Company, operator of the Summer Station and PSA are
joint owners of Summer Station in the proportions of two-thirds
and one-third, respectively. The parties share the operating
costs and energy output of the plant in these proportions. Each
party, however, provides its own financing. Plant-in-service
related to the Company's portion of Summer Station was
approximately $925.1 million and $923.1 million as of December
31, 1995 and 1994, respectively. Accumulated depreciation
associated with the Company's share of Summer Station was
approximately $261.0 million and $297.9 million as of December
31, 1995 and 1994, respectively. (See Note 2A.) The Company's
share of the direct expenses associated with operating Summer
Station is included in "Other operation" and "Maintenance"
expenses.
E. Allowance for Funds Used During Construction
AFC, a noncash item, reflects the period cost of capital
devoted to plant under construction. This accounting practice
results in the inclusion of, as a component of construction cost,
the costs of debt and equity capital dedicated to construction
investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates
for utility services. The Company has calculated AFC using
composite rates of 8.6%, 8.5% and 9.4% for 1995, 1994 and 1993,
respectively. These rates do not exceed the maximum allowable
rate as calculated under FERC Order No. 561. Interest on nuclear
fuel in process and sulfur dioxide emission allowances is
capitalized at the actual interest amount.
F. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that
date, the Company ceased the deferral of carrying costs
associated with 400 MW of electric generating capacity previously
removed from rate base and began amortizing the accumulated
deferred carrying costs on a straight-line basis over a ten-year
period. Amortization of deferred carrying costs, included in
"Depreciation and amortization," was approximately $4.2 million
for each of 1995, 1994 and 1993.
G. Revenue Recognition
Customers' meters are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the
accounting period in which the meters are read.
Fuel costs for electric generation are collected through the
fuel cost component in retail electric rates. The fuel cost
component contained in electric rates is established by the PSC
during semiannual fuel cost hearings. Any difference between
actual fuel costs and that contained in the fuel cost component
is deferred and included when determining the fuel cost component
during the next semiannual fuel cost hearing. The Company had
overcollected through the electric fuel cost component
approximately $3.8 million at December 31, 1995 and
undercollected approximately $3.5 million at December 31, 1994
which are included in "Deferred Credits - Other" and "Deferral
Debits - Other," respectively.
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, 1995 and 1994 the Company had
undercollected through the gas cost recovery procedure
approximately $4.6 million and $16.3 million, respectively, which
are included in "Deferred Debits - Other."
39
The Company's gas rate schedules for residential, small
commercial and small industrial customers include a weather
normalization adjustment, which minimizes fluctuations in gas
revenues due to abnormal weather conditions.
H. Depreciation and Amortization
Provisions for depreciation are recorded using the straight-
line method for financial reporting purposes and are based on the
estimated service lives of the various classes of property. The
composite weighted average depreciation rates were 3.02%, 3.01%,
and 2.97% for 1995, 1994 and 1993, respectively.
Nuclear fuel amortization, which is included in "Fuel used
in electric generation" and is recovered through the fuel cost
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 DOE under a contract for disposal of spent nuclear fuel.
I. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning cost
is referred to as COMReP (Cost of Money Reduction Plan). Under
this plan, funds collected through rates ($3.2 million in each of
1995 and 1994) are used to purchase insurance policies on the
lives of certain Company personnel. Through the purchase of
insurance contracts, the Company is able to take advantage of
income tax benefits and accrue earnings on the fund on a tax-
deferred basis at a rate higher than can be achieved using more
traditional funding approaches. Amounts for decommissioning
collected through electric rates, insurance proceeds, and
interest on proceeds less expenses are transferred by the Company
to an external trust fund in compliance with the financial
assurance requirements of the Nuclear Regulatory Commission.
Management intends for the fund, including earnings thereon, to
provide for all eventual decommissioning expenditures on an
after-tax basis. The trust's sources of decommissioning funds
under the COMReP program include investment components of life
insurance policy proceeds, return on investment and the cash
transfers from the Company described above. The Company records
its liability for decommissioning costs in deferred credits.
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the
electric utility industry regarding the recognition, measurement
and classification of decommissioning costs for the financial
statements of electric utilities with nuclear generating
facilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting
for removal costs, including decommissioning. If the current
electric utility industry accounting practices for such
decommissioning are changed: (1) annual provisions for
decommissioning could increase, and (2) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction of decommissioning
expense.
Pursuant to the NEPA passed by Congress in 1992, the Company
has recorded a liability for its estimated share of amounts
required by the DOE for its decommissioning fund. The liability,
approximately $3.6 million at December 31, 1995, has been
included in "Long-Term Debt, Net." The Company will recover the
cost associated with this liability through the fuel cost
component of its rates; accordingly, this amount has been
deferred and is included in "Deferred Debits - Other."
J. Income Taxes
The Company is included in the consolidated Federal income
tax return filed by SCANA. Income taxes are allocated to the
Company based on its contribution to the consolidated total.
As required by Statement of Financial Accounting Standards
No. 109, deferred tax assets and liabilities are recorded for the
tax effects of temporary differences between the book basis and
tax basis of assets and liabilities at currently enacted tax
rates. Deferred tax assets and liabilities are adjusted for
changes in such rates through charges or credits to regulatory
assets or liabilities if they are expected to be recovered from,
or passed through to, customers; otherwise, they are charged or
credited to income tax expense.
40
K. Pension Expense
The Company participates in SCANA's noncontributory defined
benefit pension plan, which covers all permanent Company
employees. Benefits are based on years of accredited service and
the employee's average annual base earnings received during the
last three years of employment. SCANA's policy has been to fund
pension costs accrued to the extent permitted by the applicable
Federal income tax regulations as determined by an independent
actuary.
Net periodic pension cost for the years ended December 31,
1995, 1994 and 1993 included the following components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 5,187 $ 8,684 $ 7,629
Interest cost on projected benefit obligation 19,473 21,711 20,413
Adjustments:
Return on plan assets (103,874) 2,365 (50,389)
Net amortization and deferral 74,769 (29,760) 25,936
Amounts contributed by the Company's
affiliates (203) (130) (175)
Net periodic pension (income) expense $ (4,648) $ 2,870 $ 3,414
The determination of net periodic pension cost is based upon
the following assumptions:
1995 1994 1993
Annual discount rate 8.0% 7.25% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 2.5% 4.75% 5.5%
The following table sets forth the funded status of the plan
at December 31, 1995 and 1994:
1995 1994
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $228,434 $205,364
Nonvested benefit obligation 15,540 13,966
Accumulated benefit obligation $243,974 $219,330
Plan assets at fair value
(invested primarily in equity and debt securities) $447,760 $347,702
Projected benefit obligation 284,145 246,318
Plan assets greater than
projected benefit obligation 163,615 101,384
Unrecognized net transition liability 9,022 11,307
Unrecognized prior service costs 9,660 9,374
Unrecognized net gain (146,943) (102,284)
Pension asset recognized in
Consolidated Balance Sheets $ 35,354 $ 19,781
The accumulated benefit obligation is based on the plan's
benefit formulas without considering expected future salary
increases. The following table sets forth the assumptions used
in determining the amounts shown above for the years 1995 and
1994.
1995 1994
Annual discount rate used to determine
benefit obligations 7.5% 8.0%
Assumed annual rate of future salary increases
for projected benefit obligation 3.0% 2.5%
41
The change in the annual discount rate used to determine
benefit obligations from 8.0% to 7.5% and the change in the
expected salary increase rate from 2.5% to 3.0% as of December
31, 1995 increased the projected benefit obligation and decreased
the unrecognized net gain by approximately $28.6 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. The costs of postretirement benefits
other than pensions are accrued during the years the employees
render the service necessary to be eligible for the applicable
benefits. Prior to 1993, the Company expensed these benefits,
which are primarily health care, as claims were incurred. In its
June 1993 electric rate order, the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. The Company expensed approximately $8.5 million and
$8.6 million, net of payments to current retirees, for the years
ended December 31, 1995 and 1994, respectively. The PSC has
authorized accelerated amortization of the Company's remaining
transition obligation for postretirement benefits other than
pensions related to electric operations. (See Note 2A.)
Net periodic postretirement benefit cost for the years ended
December 31, 1995, 1994 and 1993, included the following
components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 2,076 $ 2,417 $ 1,908
Interest cost on accumulated postretirement
benefit obligation 7,253 6,644 5,502
Adjustments:
Return on plan assets - - -
Amortization of unrecognized
transition obligation 3,344 3,344 3,344
Other net amortization and deferral 661 860 -
Amounts contributed by the Company's affiliates (610) (575) (525)
Net periodic postretirement benefit cost $12,724 $12,690 $10,229
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1995 1994 1993
Annual discount rate 8.0% 7.25% 8.0%
Health care cost trend rate 11.0% 11.25% 13.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 6.0% 5.25% 6.0%
42
The following table sets forth the funded status of the plan
at December 31, 1995 and 1994:
1995 1994
(Thousands of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 64,989 $ 59,174
Other fully eligible participants 6,685 4,995
Other active participants 27,076 24,889
Accumulated postretirement benefit obligation 98,750 89,058
Plan assets at fair value - -
Plan assets less accumulated postretirement benefit
obligation (98,750) (89,058)
Unrecognized net transition liability 58,237 61,581
Unrecognized prior service costs 5,320 3,453
Unrecognized net loss 13,840 11,156
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(21,353) $(12,868)
The accumulated postretirement benefit obligation is based upon the
plan's benefit provisions and the following assumptions:
1995 1994
Assumed health care cost trend rate used to
measure expected costs 10.5% 12.0%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.5% 6.0%
Annual discount rate 7.5% 8.0%
Annual rate of salary increases 3.0% 2.5%
The effect of a one percentage-point increase in the assumed
health care cost trend rate for each future year on the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for the year ended December 31, 1995
and the accumulated postretirement benefit obligation as of
December 31, 1995 would be to increase such amounts by $203,000
and $3.4 million, respectively.
L. Debt Premium, Discount and Expense, Unamortized Loss on
Reacquired Debt
Long-term debt premium, discount and expense are being
amortized as components of "Interest on long-term debt, net" over
the terms of the respective debt issues. Gains or losses on
reacquired debt that is refinanced are deferred and amortized
over the term of the replacement debt.
M. Environmental
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of 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 are deferred and are being
amortized and recovered through rates over a ten-year period for
electric operations and an eight-year period for gas operations.
Such deferred amounts totaled $18.0 million and $20.2 million at
December 31, 1995 and 1994, respectively, and are included in
"Deferred Debits - Other."
43
N. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide
emission allowances are purchased and financed by Fuel Company
under a contract which requires the Company to reimburse Fuel
Company for all costs and expenses relating to the ownership and
financing of fuel inventories and sulfur dioxide emission
allowances. Accordingly, such fuel inventories and emission
allowances and fuel-related assets and liabilities are included
in the Company's consolidated financial statements. (See Note 4.)
O. Temporary Cash Investments
The Company considers temporary cash investments having
original maturities of three months or less to be cash
equivalents. Temporary cash investments are generally in the
form of commercial paper, certificates of deposit and repurchase
agreements.
P. Recently Issued Accounting Standards
The Financial Accounting Standards Board has issued
Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of." The provisions of the Statement, which
will be implemented by the Company for the fiscal year beginning
January 1, 1996, require the recognition of a loss in the income
statement and related disclosures whenever events or changes in
circumstances indicate that the carrying amount of a long-lived
asset may not be recoverable. The Company does not believe that
adoption of the provisions of the Statement will have a material
impact on its results of operations or financial position.
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-
Based Compensation," which will be implemented by the Company on
January 1, 1996. The Company does not believe that adoption of
the provisions of the Statement will have a material impact on
its results of operations or financial position.
Q. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1995 presentation.
R. Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
44
2. RATE MATTERS:
A. On July 10, 1995, the Company filed an application with
the PSC for an increase in retail electric rates. On January 9,
1996 the PSC issued an order granting the Company an increase of
7.34% which will produce additional revenues of approximately
$67.5 million annually. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 million annually based on a test year, or
6.47%, commenced on January 15, 1996. The second phase will be
implemented in January 1997 and will produce additional revenues
of approximately $8.0 million annually, or .87% more than current
rates. The PSC authorized a return on common equity of 12.0%.
The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million and collected through rates over a
ten-year period. Additionally, the PSC approved accelerated
recovery of substantially all (excluding accumulated deferred
income taxes) of the Company's electric regulatory assets and the
transition obligation for postretirement benefits other than
pensions, changing the amortization periods to allow recovery by
the end of the year 2000. The Company's request to shift
approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved.
B. On October 27, 1994 the PSC issued an order approving the
Company's request to recover through a billing surcharge to its
gas customers the costs of environmental cleanup at the sites of
former manufactured gas plants. The billing surcharge, which was
effective with the first billing cycle in November 1994 and is
subject to annual review, provides for the recovery of
approximately $16.2 million representing substantially all site
assessment and cleanup costs for the Company's gas operations
that had previously been deferred. In October 1995, as a result
of the ongoing annual review, the PSC approved the continued use
of the billing surcharge. The balance remaining to be recovered
amounts to approximately $14.5 million.
C. In September 1992 the PSC issued an order granting the
Company a $.25 increase in transit fares from $.50 to $.75 in
both Columbia and Charleston, South Carolina; however, the PSC
also required $.40 fares for low-income customers and denied the
Company's request to reduce the number of routes and frequency of
service. The new rates were placed into effect in October 1992.
The Company appealed the PSC's order to the Circuit Court, which
on May 23, 1995, ordered the case back to the PSC for
reconsideration of several issues including the low-income rider
program, routing changes, and the $.75 fare. The Supreme Court
declined to review an appeal of the Circuit Court decision and
dismissed the case. Another Petition for Reconsideration was
filed by the PSC and other intervenors, which was denied by the
Circuit Court. Procedural matters in this case are yet to be
resolved in the court.
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including
amounts due under nuclear and fossil fuel agreements (see Note
4), and sinking fund requirements for the years 1996 through 2000
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1996 $ 36,033 1999 $ 17,663
1997 33,252 2000 117,668
1998 114,483
Approximately $17.3 million of the portion of long-term debt
payable in 1996 may be satisfied by either deposit and
cancellation of bonds issued upon the basis of property additions
or bond retirement credits, or by deposit of cash with the
Trustee.
45
The Company has three-year revolving lines of credit
totaling $100 million, in addition to other lines of credit, that
provide liquidity for issuance of commercial paper. The three-
year lines of credit provide back-up liquidity when commercial
paper outstanding is in excess of $100 million. The long-term
nature of the lines of credit allow commercial paper in excess of
$100 million to be classified as long-term debt. The Company had
outstanding commercial paper of $111.2 million at December 31,
1994, of which $11.2 million was reclassified to long-term debt.
Certain outstanding long-term debt of an affiliated
company (approximately $35.9 million at both December 31, 1995
and 1994) is guaranteed by the Company.
Substantially all utility plant and fuel inventories are
pledged as collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories and sulfur dioxide
emission allowances are financed through the issuance by Fuel
Company of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires July 31, 1998. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $125 million that may
be outstanding at any time.
Commercial paper outstanding totaled $76.8 million and $50.6
million at December 31, 1995 and 1994 at weighted average
interest rates of 5.76% and 6.06%, respectively.
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including
Preferred Stock Not Subject to Purchase or Sinking Funds) during
1995, 1994 and 1993 are summarized as follows:
Common Preferred Thousands
Shares Shares of Dollars
Balance December 31, 1992 40,296,147 322,877 $989,768
Changes in Retained Earnings:
Net Income 145,968
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,217)
Common Stock (110,300)
Equity Contributions from Parent 58,142
Balance December 31, 1993 40,296,147 322,877 1,077,361
Changes in Retained Earnings:
Net Income 152,043
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,955)
Common Stock (113,700)
Equity Contributions from Parent 49,710
Balance December 31, 1994 40,296,147 322,877 1,159,459
Changes in Retained Earnings:
Net Income 169,185
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,687)
Common Stock (121,363)
Equity Contributions from Parent
including transfer of assets 139,505
Balance December 31, 1995 40,296,147 322,877 $1,341,099
46
The Restated Articles of Incorporation of the Company and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions that under
certain circumstances could limit the payment of cash dividends on common
stock. In addition, with respect to hydroelectric projects, the Federal
Power Act requires the appropriation of a portion of the earnings
therefrom. At December 31, 1995 approximately $14.5 million of
retained earnings were restricted by this requirement as to payment of cash
dividends on common stock.
6. PREFERRED STOCK (Subject to Purchase or Sinking Funds):
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend. Retirements under sinking
fund requirements are at par values.
The aggregate annual amounts of purchase fund or sinking fund requirements
for preferred stock for the years 1996 through 2000 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1996 $2,439 1999 $2,440
1997 2,440 2000 2,440
1998 2,440
The changes in "Total Preferred Stock (Subject to Purchase or Sinking
Funds)" during 1995, 1994 and 1993 are summarized as follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1992 940,529 $ 58,639
Shares Redeemed:
$100 par value (7,374) (737)
$50 par value (51,187) (2,558)
Balance December 31, 1993 881,968 55,344
Shares Redeemed:
$100 par value (8,072) (807)
$50 par value (51,802) (2,591)
Balance December 31, 1994 822,094 51,946
Shares Redeemed:
$100 par value (6,809) (681)
$50 par value (51,666) (2,583)
Balance December 31, 1995 763,619 $ 48,682
7. INCOME TAXES:
Total income tax expense for 1995, 1994 and 1993 is as follows:
1995 1994 1993
(Thousands of Dollars)
Current taxes:
Federal $ 94,137 $66,597 $60,577
State 14,265 9,505 6,822
Total current taxes 108,402 76,102 67,399
Deferred taxes, net:
Federal (7,319) 7,727 12,197
State (603) 2,118 4,387
Total deferred taxes (7,922) 9,845 16,584
Investment tax credits:
Amortization of amounts
deferred (credit) (3,230) (3,231) (3,245)
Total income tax expense $ 97,250 $82,716 $80,738
47
The difference in actual income taxes and the income taxes
calculated from the application of the statutory Federal income
tax rate (35% for 1995, 1994 and 1993) to pretax income is
reconciled as follows:
1995 1994 1993
(Thousands of Dollars)
Net income $169,185 $152,043 $145,968
Total income tax expense:
Charged to operating expenses 96,956 84,066 81,280
Charged (credited) to other income 294 (1,350) (542)
Total pretax income $266,435 $234,759 $226,706
Income taxes on above at statutory
Federal income tax rate $ 93,252 $ 82,166 $ 79,347
Increases (decreases) attributable to:
Allowance for equity funds used
during construction (3,325) (2,796) (2,624)
Amortization of deferred
return on plant investment 1,486 1,486 1,486
Depreciation differences 3,268 2,994 2,531
Amortization of investment
tax credits (3,230) (3,231) (3,245)
State income taxes (less Federal
income tax effect) 8,880 7,555 7,286
Deferred income tax flowback at
higher than statutory rates (3,310) (3,647) (3,641)
Other differences, net 229 (1,811) (402)
Total income tax expense $ 97,250 $ 82,716 $ 80,738
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $468.9
million at December 31, 1995 and $485.8 million at December 31,
1994 determined in accordance with Statement No. 109 (see Note
1J) are as follows:
1995 1994
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 48,512 $ 50,513
Cycle billing 19,143 17,521
Nuclear operations expenses 3,755 206
Deferred compensation 5,562 5,450
Other postretirement benefits 6,371 3,187
Other 2,929 3,627
Total deferred tax assets 86,272 80,504
Deferred tax liabilities:
Property plant and equipment 520,294 533,394
Pension expense 14,191 9,022
Reacquired debt 6,680 7,146
Research and experimentation 6,196 2,276
Other 7,801 14,458
Total deferred tax liabilities 555,162 566,296
Net deferred tax liability $468,890 $485,792
The Internal Revenue Service has examined and closed consolidated
Federal income tax returns of SCANA Corporation through 1989 and
is currently examining SCANA's 1990, 1991 and 1992 Federal income
tax returns. Adjustments are currently proposed by the examining
agent. SCANA does not anticipate that any adjustments which
might result from this examination will have a significant impact
on the earnings or financial position of the Company.
48
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the
Company's financial instruments at December 31, 1995 and 1994 are
as follows:
1995 1994
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
Cash and temporary cash
investments $ 6,798 $ 6,798 $ 346 $ 346
Investments 61 61 61 61
Liabilities:
Short-term borrowings 81 81 100,000 100,000
Notes payable - affiliated
companies - - 19,409 19,409
Long-term debt 1,315,412 1,412,213 1,264,233 1,195,023
Preferred stock (subject
to purchase or sinking funds) 48,682 46,603 51,946 49,348
The information presented herein is based on pertinent
information available to the Company as of December 31, 1995 and
1994. Although the Company is not aware of any factors that
would significantly affect the estimated fair value amounts, such
financial instruments have not been comprehensively revalued
since December 31, 1995, and the current estimated fair value may
differ significantly from the estimated fair value at that date.
The following methods and assumptions were used to estimate
the fair value of the above classes of financial instruments:
Cash and temporary cash investments, including commercial
paper, repurchase agreements, treasury bills and notes are valued
at their carrying amount.
Fair values of investments and long-term debt are based on
quoted market prices of the instruments or similar instruments,
or for those instruments for which there are no quoted market
prices available, fair values are based on net present value
calculations. Settlement of long term debt may not be possible
or may not be a prudent management decision.
Short-term borrowings are valued at their carrying amount.
The fair value of preferred stock (subject to purchase or
sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in
an actual sale or settlement have not been taken into
consideration.
49
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its
committed lines of credit. Commercial paper borrowings are for
270 days or less. Details of lines of credit and short-term
borrowings, excluding amounts classified as long-term (Notes 3
and 4), at December 31, 1995, 1994 and 1993 and for the years
then ended are as follows:
1995 1994 1993
(Millions of dollars)
Authorized lines of credit at year-end $165.0 $165.0 $212.0
Unused lines of credit at year-end $165.0 $165.0 $212.0
Short-term borrowings outstanding at
year-end:
Commercial paper $ 80.5 $100.0 $ 1.0
Weighted average interest rate 5.83% 6.04% 3.35%
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
The Company entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina.
Construction of the plant started in November 1992. Commercial
operation began in January 1996. The cost of the Cope plant,
excluding AFC, is $410.9 million. In addition, the transmission
lines for interconnection with the Company's system cost $22.5
million.
Under the Duke/Fluor Daniel contract the aggregate amount of
required minimum payments remaining at December 31, 1995 is $4.2
million due in 1996. Through December 31, 1995 the Company had
paid $378.7 million under the contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with the
Company's public liability for a nuclear incident, currently
establishes the liability limit for third-party claims associated
with any nuclear incident at $8.9 billion. Each reactor licensee
is currently liable for up to $79.3 million per reactor owned for
each nuclear incident occurring at any reactor in the United
States, provided that not more than $10 million of the liability
per reactor would be assessed per year. The Company's maximum
assessment, based on its two-thirds ownership of Summer Station,
would be approximately $52.9 million per incident, but not more
than $6.7 million per year.
The Company currently maintains policies (for itself and on
behalf of the PSA) with Nuclear Electric Insurance Limited (NEIL)
and American Nuclear Insurers (ANI) providing combined property
and decontamination insurance coverage of $1.9 billion for any
losses at Summer Station. The Company pays annual premiums and,
in addition, could be assessed a retroactive premium not to
exceed 7 1/2 times its annual premium in the event of property
damage loss to any nuclear generating facilities covered under
the NEIL program. Based on the current annual premium, this
retroactive premium would not exceed $8.2 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and
expenses arising from a nuclear incident at Summer Station exceed
the policy limits of insurance, or to the extent such insurance
becomes unavailable in the future, and to the extent that the
Company's rates would not recover the cost of any purchased
replacement power, the Company will retain the risk of loss as a
self-insurer. The Company has no reason to anticipate a serious
nuclear incident at Summer Station. If such an incident were to
occur, it could have a material adverse impact on the Company's
financial position and results of operations.
50
C. Environmental
As described in Note 1M of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, estimates are made of the cost, if any, to investigate
and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual
expenditures could differ significantly from original estimates.
Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations; such amounts
are deferred and are being amortized and recovered through rates
over a ten-year period for electric operations and an eight-year
period for gas operations. Such deferred amounts totaled $18.0
million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates to date include, among other items, the
costs estimated to be associated with the matters discussed in
the following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.
In September 1992 the EPA notified the Company, the City of
Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the
Calhoun Park Area Site in Charleston, South Carolina. This site
originally encompassed approximately eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority List, but may
be added before cleanup is initiated. The PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigation process to be
compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study (RI/FS) and a corresponding Scope
of Work. Field work began in November 1993. The Company is also
working with the City of Charleston to investigate potential
contamination from the manufactured gas plant which may have
migrated to the city's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to
be responsible for a $43.5 million increase in costs of the
aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes it has meritorious defenses against this claim and does
not expect its resolution to have a material impact on its
financial position or results of operations.
D. Claims and Litigation
The Company is engaged in various claims and litigation
incidental to its business operations which management
anticipates will be resolved without loss to the Company. No
estimate of the range of loss from these matters can currently be
determined.
51
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1995, 1994 and 1993 and
for the years then ended is as follows:
1995
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $1,006,566 $ 200,632 $ 3,889 $1,211,087
Operating expenses,
excluding depreciation
and amortization 657,452 169,768 10,429 837,649
Depreciation and
amortization 103,961 12,616 1,007 117,584
Total operating expenses 761,413 182,384 11,436 955,233
Operating income (loss) $ 245,153 $ 18,248 $ (7,547) 255,854
Add - Other income, net 9,553
Less - Interest charges 96,222
Net income $ 169,185
Capital expenditures:
Identifiable $ 245,016 $ 19,670 $ 265 $ 264,951
Utilized for overall Company operations 27,816
Total $ 292,767
Identifiable assets at
December 31, 1995:
Utility plant, net $2,850,647 $ 209,847 $ 1,878 $3,062,372
Inventories 76,697 2,155 561 79,413
Total $2,927,344 $ 212,002 $ 2,439 3,141,785
Other assets 660,648
Total assets $3,802,433
1994
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $975,526 $201,746 $ 4,002 $1,181,274
Operating expenses,
excluding depreciation
and amortization 659,610 173,717 10,577 843,904
Depreciation and
amortization 95,666 11,060 226 106,952
Total operating expenses 755,276 184,777 10,803 950,856
Operating income (loss) $ 220,250 $ 16,969 $ (6,801) 230,418
Add - Other income, net 7,271
Less - Interest charges 85,646
Net income $ 152,043
Capital expenditures:
Identifiable $ 359,510 $ 40,923 $ 347 $ 400,780
Utilized for overall Company operations 20,167
Total $ 420,947
Identifiable assets at
December 31, 1994:
Utility plant, net $2,717,147 $201,018 $ 1,791 $2,919,956
Inventories 85,113 2,605 495 88,213
Total $2,802,260 $203,623 $ 2,286 3,008,169
Other assets 578,922
Total assets $3,587,091
52
1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,547 $174,035 $ 3,851 $1,118,433
Operating expenses,
excluding depreciation
and amortization 639,808 148,349 9,737 797,894
Depreciation and
amortization 91,142 9,903 175 101,220
Total operating expenses 730,950 158,252 9,912 899,114
Operating income (loss) $ 209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585
Less - Interest charges 79,936
Net income $ 145,968
Capital expenditures:
Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934
Total $ 300,620
Identifiable assets at
December 31, 1993:
Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603
Inventories 66,181 2,526 463 69,170
Total $2,511,647 $180,990 $2,136 2,694,773
Other assets 495,166
Total assets $3,189,939
53
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1995
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $308,759 $275,139 $339,937 $287,252 $1,211,087
Operating income 67,189 53,153 87,023 48,489 255,854
Net Income 45,249 30,870 65,040 28,026 169,185
1994
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $313,321 $263,033 $327,066 $277,854 $1,181,274
Operating income 63,520 43,316 79,133 44,449 230,418
Net Income 45,340 24,348 57,619 24,736 152,043
54
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
The directors listed below were elected April 27, 1995 to hold office
until the next annual meeting of the Company's stockholders on April 25, 1996.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 52 For more than five years, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).
For more than five years, Chairman and Chief
Executive Officer of Amick Processing, Inc.
and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia, SC.
William B. Bookhart, Jr. 54 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 66 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC;
South Carolina National Corporation,
Columbia, SC; Wachovia Bank of South
Carolina, N.A., Columbia, SC.
Hugh M. Chapman 63 Since January 1, 1992, Chairman of
(1988) NationsBank South, Atlanta, GA (a division
of NationsBank Corporation, bank holding
company).
From September 1, 1990 to December 31, 1991,
Vice Chairman and Director, C&S/Sovran
Corporation, Atlanta, GA.
Prior to September 1, 1990, President and
Director, Citizens & Southern
Corporation, Atlanta, GA and Chairman
of the Board, Citizens & Southern
South Carolina Corporation, Columbia,
SC.
Director, SCANA Corporation, Columbia, SC.
55
Name and Year First
Became Director Age Principal Occupation; Directorships
James B. Edwards, D.M.D. 68 For more than five years, President and
(1986) Professor of Maxillofacial Surgery,
Medical University of South Carolina,
Charleston, SC.
U.S. Secretary of Energy from January
1981 to November 1982.
Governor of South Carolina, 1975-1979.
Director, Phillips Petroleum Co.,
Bartlesville, OK; WMX Technologies, Inc.,
Oak Brook, IL; General Engineering
Laboratories, Inc., Charleston SC;
GS Industries, Inc., Charlotte, NC; IMO
Industries, Inc., Lawrenceville, NJ;
National Data Corporation, Atlanta, GA;
SCANA Corporation, Columbia, SC.
Elaine T. Freeman 60 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg,
SC.
Director National Bank of South Carolina,
Columbia, SC; SCANA Corporation,
Columbia, SC.
Lawrence M. Gressette, Jr. 64 For more than five years, Chairman of the
(1987) Board and Chief Executive Officer
of SCANA Corporation and Chairman
of the Board and Chief Executive
Officer of all SCANA subsidiaries,
including the Company.
For more than five years prior to
December 13, 1995, President of
SCANA Corporation.
Director, Wachovia Corporation, Winston-
Salem, NC; InterCel, Inc., West Point, GA;
The Liberty Corporation, Greenville, SC;
SCANA Corporation, Columbia, SC.
Benjamin A. Hagood 68 Since January 1, 1993, Chairman of the
(1974) Board William M. Bird and Company, Inc.,
Inc., Charleston, SC (wholesale
distributor of floor covering material).
For more than two years prior to January 1,
1993, President and Director, William M.
Bird and Company, Inc., Charleston, SC.
Director, SCANA Corporation, Columbia, SC.
56
Name and Year First
Became Director Age Principal Occupation; Directorships
W. Hayne Hipp 56 For more than five years, President and
(1983) Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance
and broadcasting holding company).
Director, The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC; SCANA Corporation,
Columbia, SC.
Bruce D. Kenyon 53 For more than five years, President and
(1991) Chief Operating Officer of the Company.
Director, SCANA Corporation, Columbia, SC.
F. Creighton McMaster 66 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor
of petroleum products).
Director, First Union National Bank of
South Carolina, Greenville, SC; SCANA
Corporation, Columbia, SC.
Henry Ponder, Ph.D. 67 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Suntrust Banks, Inc., Nashville,
TN; SCANA Corporation, Columbia, SC.
John B. Rhodes 65 For more than five years, Chairman and
(1967) Chief Executive Officer, Rhodes Oil
Company, Inc., Walterboro, SC
(distributor of petroleum products).
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 49 Since December 13, 1995, President of SCANA
(1991) Corporation.
From May 1, 1994 to December 13, 1995,
Executive Vice President of SCANA
Corporation.
Since August 25, 1993, Assistant Secretary
of SCANA Corporation and all of its
subsidiaries, including the Company.
From August 28, 1991 to February 20, 1996,
Chief Financial Officer of the Company.
For more than five years prior to May 1,
1994, Senior Vice President of SCANA
SCANA Corporation.
For more than five years prior to February
20, 1996, Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC;
InterCel, Inc., West Point, GA.
57
Name and Year First
Became Director Age Principal Occupation; Directorships
E. Craig Wall, Jr. 58 For more than five years, President and
(1982) Director, Canal Industries, Conway, SC
(forest products industry).
Director, Sonoco Products Company,
Hartsville, SC; Ruddick Corporation,
Charlotte, NC; Nationsbank Corp.,
Charlotte, NC; Blue Cross/Blue Shield of
South Carolina, Columbia, SC; SCANA
Corporation, Columbia, SC.
58
EXECUTIVE OFFICERS OF THE COMPANY
The Company's officers are elected at the annual organizational meeting of
the Board of Directors and hold office until the next such organizational
meeting, unless the Board of Directors shall otherwise determine, or unless
a resignation is submitted.
Positions Held During
Name Age Past Five Years Dates
L.M. Gressette, Jr. (1) 64 Chairman of the Board and
Chief Executive Officer *-present
President - SCANA *-1995
B.D. Kenyon (1) 53 President and Chief
Operating Officer 1990-present
W.B. Timmerman (1) 49 President - SCANA 1995-present
President of MPX, an
affiliate 1996-present
Executive Vice President, 1994-1995
SCANA
Assistant Secretary 1993-1996
Chief Financial Officer *-1996
Controller, SCANA *-1996
Senior Vice President, *-1994
SCANA
G.J. Bullwinkel, Jr. 47 Senior Vice President-
Retail Electric 1995-present
Senior Vice President-
Fossil & Hydro Production 1993-1994
Senior Vice President-
Production 1991-1992
W.A. Darby 50 Senior Vice President -
Gas, SCANA Gas Group 1996-present
Vice President-Gas Operations *-present
President and Treasurer of
ServiceCare 1996-present
General Manager of ServiceCare,
Inc., an affiliate 1994-present
J. L. Skolds 45 Senior Vice President - 1994-present
Generation
Vice President - Nuclear
Operations 1990-1994
K. B. Marsh (1) 40 Vice President - Finance,
Chief Financial Officer
and Controller - SCANA 1996-present
Vice President - Finance,
Treasurer and Secretary 1992-1996
Vice President - Finance
and Treasurer 1991-1992
Vice President - Corporate
Planning 1991
Vice President and
Controller *-1991
B.T. Zeigler (1) 40 Vice President - SCANA 1996-present
General Counsel of SCE&G 1995-present
Associate General Counsel -
SCE&G Legal Department 1992-1995
Partner - Lewis, Babcock &
Hawkins Law Firm *-1992
*Indicates position held at least since March 1, 1991
(1) Also an executive officer of SCANA
59
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
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 indicate that no equity securities of the
Company are owned by the directors and executive officers. Based
solely on a review of the copies of such forms and amendments
furnished to the Company and written representations from the
executive officers and directors, the Company believes that during
1995 all Section 16(a) filing requirements applicable to its executive
officers, directors and greater than 10% beneficial owners were
complied with except that one report covering initial ownership of the
Company's preferred stock was filed late by Kevin B. Marsh and Belton
T. Zeigler.
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to
compensation paid or accrued during the years 1995, 1994 and 1993 to
the Chief Executive Officer of the Company and to each of the other
four most highly compensated executive officers of the Company during
1995 who were serving as executive officers of the Company at the end
of 1995.
SUMMARY COMPENSATION TABLE
Name and Principal Year Annual Compensation Long-Term
Position Compensation
(1) (2)
Salary Bonus Other Payouts
($) ($) Annual
Compen-
sation
($) (3) (4)
LTIP All Other
Payouts Compensa-
($) tion ($)
L. M. Gressette, Jr. 1995 449,246(5) 197,500 65,779 390,156 26,955
Chairman of the 1994 416,609 0 2,255 173,375 24,996
Board and Chief 1993 383,557 186,615 61,699 266,007 23,013
Executive Officer
B. D. Kenyon 1995 318,542 104,353 7,107 172,240 19,113
President and Chief 1994 313,581 96,768 2,649 81,619 18,815
Operating Officer 1993 297,760 99,090 4,201 125,792 17,866
W. B. Timmerman 1995 254,214 101,588 987 150,353 15,127
Chief Financial 1994 235,099 19,725 1,323 70,751 14,106
Officer and 1993 220,752 95,738 2,828 109,768 13,245
Assistant Secretary
G. J. Bullwinkel 1995 189,097 70,904 487 90,402 11,346
Senior Vice President 1994 170,828 42,573 762 38,249 9,826
- - Retail Electric 1993 148,705 51,975 1,477 58,489 0
J. L. Skolds 1995 176,156 74,151 54 76,128 10,569
Senior Vice President 1994 156,731 42,573 2,146 38,249 9,404
- - Generation 1993 146,438 43,605 4,065 58,489 0
______________
(1) Payments under the annual Performance Incentive Plan described hereafter.
(2) Other annual compensation consists of (i) for Mr. Gressette, perquisites
including compensation related to whole life insurance premiums for 1995
in the amount of $54,642, (ii) for Mr. Kenyon, a lump sum payment in lieu
of a base salary increase in 1995 and (iii) for all named officers,
payments to cover taxes on benefits.
(3) Payments under the long-term Performance Share Plan described hereafter.
(4) All other compensation consists solely of Company contributions to defined
contribution plans based on the funding formula applicable to all
employees of the Company.
(5) Reflects actual salary paid in 1995. Base salary of $460,000, became
effective in May of 1995.
60
Long-Term Performance Share Plan
The long-term Performance Share Plan for officers of SCANA and
its subsidiaries measures SCANA's Total Shareholder Return ("TSR")
relative to a group of peer companies over a three-year period. The
"PSP Peer Group" includes 94 electric and gas utilities, none of which
have annual revenues of less than $100 million.
TSR is stock price increase over the three-year period, plus cash
dividends paid during the period, divided by stock price as of the
beginning of the period. Comparing SCANA's TSR to the TSR of a large
group of other utilities reflects SCANA's recognition that investors
could have invested their funds in other utility companies and
measures how well SCANA did when compared to others operating in
similar interest, tax, economic and regulatory environments.
Executives eligible to participate in the Performance Share Plan
are assigned target award opportunities annually based primarily on
their salary level. In determining award sizes, levels of
responsibilities and competitive practices also are considered.
Awards under this plan represent a significant portion of executives
"at-risk" compensation. To provide additional incentive for
executives, and to ensure that executives are only rewarded when
shareholders gain, actual payouts may exceed the median of the market
when performance is above the 50th percentile of the peer group. For
lesser performance, awards will be at or below the market median.
Payouts occur when SCANA's TSR is in the top two-thirds of the
PSP Peer Group, and vary based on SCANA's ranking against the peer
group. Executives earn threshold payouts of 0.4 times target at the
33rd percentile of three-year performance. Target payouts will be
made at the 50th percentile of three-year performance. Maximum
payouts will be made at 1.5 times target when SCANA's TSR is at or
above the 75th percentile of the peer group. Payments will be made on
a sliding scale for performance between threshold and target and
target and maximum. No payouts will be earned if performance is in
the bottom one-third of the peer group. Awards are denominated in
shares of SCANA Common Stock and may be paid in either stock or a
combination of stock and cash.
For the three-year period from 1993 through 1995, SCANA's TSR was
at the 98th percentile of the PSP Peer Group. This resulted in
payouts in February 1996 at 150% of target shares awarded paid in a
combination of stock and cash.
The following table shows the target awards made in 1995 for
potential payment in 1998 under the long-term Performance Share Plan,
and estimated future payouts under that plan at threshold, target and
maximum levels for the named executive officers. Mr. Gressette's
award for the 1995-1997 performance period is prorated to reflect his
retirement in February 1997.
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1995 TO BE PAID IN 1998
Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation
Name Rights (#) or Payout
Threshold Target Maximum
($ or #) ($ or #) ($ or #)
L. M. Gressette, Jr. 6,023 1995-1997 2,409 6,023 9,035
B. D. Kenyon 3,700 1995-1997 1,480 3,700 5,550
W. B. Timmerman 3,220 1995-1997 1,288 3,220 4,830
G. J. Bullwinkel 1,940 1995-1997 776 1,940 2,910
J. L. Skolds 1,940 1995-1997 776 1,940 2,910
61
DEFINED BENEFIT PLANS
In addition to the qualified Retirement Plan for all employees,
the Company has Supplemental Executive Retirement Plans ("SERP") for
certain eligible employees, including officers. A SERP is an unfunded
plan which provides for benefit payments in addition to those payable
under a qualified retirement plan. It maintains uniform application
of the Retirement Plan benefit formula and would provide, among other
benefits, payment of Retirement Plan formula pension benefits, if any,
which exceed those payable under the Internal Revenue Code ("IRC")
maximum benefit limitations.
The following table illustrates the estimated maximum annual
benefits payable upon retirement at normal retirement date under the
Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$150,000 42,311 56,415 70,519 84,623 87,476
200,000 57,311 76,415 95,519 114,623 118,726
250,000 72,311 96,415 120,519 144,623 149,976
300,000 87,311 116,415 145,519 174,623 181,226
350,000 102,311 136,415 170,519 204,623 212,476
400,000 117,311 156,415 195,519 234,623 243,726
450,000 132,311 176,415 220,519 264,623 274,976
500,000 147,311 196,415 245,519 294,623 306,226
550,000 162,311 216,415 270,519 324,623 337,476
600,000 177,311 236,415 295,519 354,623 368,726
The compensation shown in the column labeled "Salary" of the
Summary Compensation Table for the individuals named therein is
covered by the Retirement Plan and/or a SERP. As of December 31,
1995, Messrs. Gressette, Kenyon, Timmerman, Bullwinkel and Skolds had
credited service under the Retirement Plan (or its equivalent under
the SERP) of 33, 22, 17, 25 and 10 years, respectively. Benefits are
computed based on a straight-life annuity with an unreduced 60%
surviving spouse benefit. The amounts in this table assume
continuation of the primary Social Security benefits in effect at
January 1, 1996 and are not subject to any deduction for Social
Security or other offset amounts.
The Company also has a Key Employee Retention Program (the "Key
Employee Retention Program") covering officers and certain other
executive employees that provides supplemental retirement and/or death
benefits for participants. Under the program, each participant may
elect to receive either a monthly retirement benefit for 180 months
upon retirement at or after age 65 equal to 25% of the average monthly
salary of the participant over his final 36 months of employment prior
to age 65, or an optional death benefit payable to a participant's
designated beneficiary monthly for 180 months, in an amount equal to
35% of the average monthly salary of the participant over his final 36
months of employment prior to age 65. In the event of the
participant's death prior to age 65, the Company will pay to the
participant's designated beneficiary for 180 months, a monthly benefit
equal to 50% of such participant's base monthly salary in effect at
death.
All of the executive officers named in the Summary Compensation
Table above are participating in the program. Estimated annual
retirement benefits payable at age 65 based on projected eligible
compensation (assuming increases of 4% per year) to the five executive
officers named in the Summary Compensation Table are as follows:
Mr. Gressette - $113,790; Mr. Kenyon - $122,658; Mr. Timmerman -
$129,942; Mr. Bullwinkel - $90,887; and Mr. Skolds - $93,234.
62
TERMINATION, SEVERANCE AND CHANGE OF CONTROL ARRANGEMENTS
The Company has a Key Executive Severance Benefit Plan (the
"Severance Plan") intended to assure the objective judgment of, and to
retain the loyalties of, key executives when the Company is faced with
a potential change in control or a change in control by providing a
continuation of salary and benefits after a participant's employment
is terminated by the Company during a potential change in control,
after a change in control without just cause, disability, retirement
or death or by the participant for good reason after a change in
control. All of the executive officers named in the Summary
Compensation Table except Mr. Gressette have been designated as
participants in the Severance Plan.
When a potential change in control occurs, a participant is obli-
gated to remain with the Company for six months unless his employment
is terminated for disability or normal retirement or until a change in
control occurs. Upon a change in control resulting in an officer's
termination, the Severance Plan provides for guaranteed severance
payments equal to three times the annual compensation of the officer
plus payments under certain of the Company's incentive and retirement
plans. The officer also would receive an additional amount (a "gross-
up" payment) for any IRC Section 4999 excess tax or any such other
similar tax applicable to the severance payments. In addition, for 36
months after termination, the officer would receive coverage for
medical benefits and life insurance so as to provide the same level of
benefits previously enjoyed under group plans or individual policy
contracts or otherwise as determined by the Executive Committee of the
Board of Directors. Such benefits however would be reduced to the
extent that the participant receives similar benefits during the
period from another employer.
In addition to the Severance Plan, in the event of a merger,
consolidation or acquisition in which SCANA is not the surviving
corporation, target awards under the Performance Share Plan will
become immediately payable based on SCANA's shareholder return
performance as of the end of the most recently completed calendar year
for each performance period as to which the grant of target shares has
occurred at least six months previously.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1995, no officer, employee or former officer of the
Company or its affiliates served as a member of the Long-Term
Compensation Committee or the Performance Committee, except Mr.
Gressette who served as a member of the Performance Committee.
Although Mr. Gressette was an ex-officio, nonvoting member of the
Performance Committee during 1995, he did not participate in any of
its deliberations concerning executive officer compensation.
Since January 1, 1995, the Company has engaged in business
transactions with entities with which Mr. Chapman (Chairman of both
the Performance Committee and the Long-Term Compensation Committee)
and Mr. McMaster (a member of the Long-Term Compensation Committee)
are executive officers.
Mr. Chapman is Chairman of NationsBank South, a division of
NationsBank Corporation. Since January 1, 1995, the Company has
engaged in various transactions in which affiliates of NationsBank
Corporation acted as lender or provider of lines of credit or credit
support to the Company and its affiliates. The amount paid during
1995 by the Company and its affiliates to NationsBank Corporation
affiliates on account of such transactions was $3,339,270. It is
anticipated that transactions such as described above will continue in
the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum
Company. Purchases from Winnsboro Petroleum Company totaling $71,413
for fuel oil and gasoline were made during 1995 by the Company and its
affiliates. It is anticipated that such purchases will continue in
the future.
During 1995, there existed one executive officer-director
interlock where an executive officer of SCANA Corporation served as a
director of another company that had an executive officer serving on
one of the SCANA Board of Directors' committees which deals with
compensation matters. Mr. Gressette, Chairman of the Board and Chief
Executive Officer of the Company, served as a director of The Liberty
Corporation and Mr. Hipp, President and Chief Executive Officer of The
Liberty Corporation, served as a member of the Company's Long-Term
Compensation Committee.
63
Compensation of Directors
Fees. During 1995, directors who were not employees of the
Company were paid $16,000 annually for services rendered, plus $1,800
for each Board meeting attended and $850 for attendance at a committee
meeting which is not held on the same day as a regular meeting of the
Board. The fee for attendance at a telephone conference meeting is
$200. The fee for attendance at a conference is $850. In addition,
directors are paid, as part of their compensation, travel, lodging and
incidental expenses related to attendance at meetings and conferences.
Directors who are employees of the Company or its affiliates receive
no compensation for serving as directors or attending meetings.
Deferral Plan. SCANA has a plan pursuant to which directors may
defer all or a portion of their fees for services rendered and meeting
attendance. Interest is earned on the deferred amounts at a rate set
by the Performance Committee. During 1995 and currently, the rate is
set at the announced prime rate of Wachovia Bank of South Carolina.
Mr. Cassels and Mr. Rhodes were the only directors participating in
the plan during 1995. Mr. Cassels became a participant in January
1994 and Mr. Rhodes in July 1987, and interest credited to their
deferral accounts during 1995 was $3,591.94 and $19,557.86,
respectively.
Endowment Plan. Each director participates in the Directors'
Endowment Plan, which provides that SCANA make a tax deductible,
charitable contribution totaling $500,000 to institutions of higher
education nominated by the director. A portion is contributed upon
retirement of the director and the remainder upon the director's
death. The plan is funded in part through insurance on the lives of
the directors. Designated in-state institutions of higher education
must be approved by the Chief Executive Officer of SCANA; any out-of-
state designation must be approved by the Performance Committee. The
designated institutions are reviewed on an annual basis by the Chief
Executive Officer to assure compliance with the intent of the program.
The plan is intended to reinforce SCANA's commitment to quality higher
education and is intended to enhance SCANA's ability to attract and
retain qualified board members.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
All shares of the Company's Common Stock are held, beneficially
and of record, by SCANA Corporation.
The table set forth below indicates the shares of SCANA's Common
Stock beneficially owned as of March 8, 1996 by each director and
nominee, each of the executive officers named in the Summary
Compensation Table on page 59, and the directors and executive
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 2,486 W. Hayne Hipp 2,800
W. B. Bookhart, Jr. 15,761 B. D. Kenyon 18,883
G. J. Bullwinkel 17,255 F. C. McMaster 5,630
W. T. Cassels, Jr. 2,000 Henry Ponder 12,381
H. M. Chapman 6,000 J. B. Rhodes 7,780
J. B. Edwards 4,665 J. L. Skolds 6,414
E. T. Freeman 4,220 W. B. Timmerman 36,459
L. M. Gressette, Jr. 47,493 E. C. Wall, Jr. 14,000
B. A. Hagood 2,370
All directors and executive officers as a group (21 persons) TOTAL 247,243
TOTAL PERCENT OF CLASS 0.2%
The information set forth above as to the security ownership has
been furnished to the Company by such persons.
_____________________
1 Includes shares owned by close relatives, the beneficial
ownership
of which is disclaimed by the director or nominee, as follows:
Mr. Amick - 480; Mr. Bookhart - 4,498; Mr. Gressette - 1,060;
Mr. Hagood - 334; Mr. McMaster - 2,000.
Includes shares purchased through December 31, 1995, but not
thereafter, by the Trustee under the Savings Plan.
64
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related
transactions, see Item 11, "Compensation Committee Interlocks and
Insider Participation."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
Financial Statements and Schedules
See Index to Consolidated Financial Statements and
Supplementary Data on page 30.
Exhibits Filed
Exhibits required to be filed with this Annual Report on
Form 10-K are listed in the Exhibit Index following the signature
page. Certain of such exhibits which have heretofore been filed
with the Securities and Exchange Commission and which are
designated by reference to their exhibit number in prior filings
are hereby incorporated herein by reference and made a part
hereof.
As permitted under Item 601(b)(4)(iii), instruments defining
the rights of holders of long-term debt of less than 10 percent
of the total consolidated assets of the Company and its
subsidiaries, have been omitted and the Company agrees to furnish
a copy of such instruments to the Commission upon request.
Reports on Form 8-K
None
65
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
(REGISTRANT) SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY (SIGNATURE) s/Bruce D. Kenyon
(NAME AND TITLE) Bruce D. Kenyon, President and Chief
Operating Officer
DATE February 20, 1996
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.
(i) Principal executive officer:
BY (SIGNATURE) s/L. M. Gressette, Jr.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board,
Chief Executive Officer and Director
DATE February 20, 1996
(ii) Principal financial officer:
BY (SIGNATURE) s/K. B. Marsh
(NAME AND TITLE) K. B. Marsh, Chief Financial Officer
DATE February 20, 1996
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and Controller
DATE February 20, 1996
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 20, 1996
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 20, 1996
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 20, 1996
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 20, 1996
66
BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 20, 1996
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 20, 1996
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 20, 1996
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Director
DATE February 20, 1996
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 20, 1996
BY (SIGNATURE) s/E. C. Wall, Jr.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 20, 1996
67
SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially
EXHIBIT INDEX Numbered
Number Pages
2. Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession
Not Applicable
3. Articles of Incorporation and By-Laws
A. Restated Articles of Incorporation of the
Company as adopted on December 15, 1993
(Exhibit 3-A to Form 10-Q for the quarter
ended June 30, 1994, File No. 1-3375).................... #
B. Articles of Amendment, dated June 7, 1994,
filed June 9, 1994 (Exhibit 3-B to Form 10-Q
for the quarter ended June 30, 1994, File No. 1-3375).... #
C. Articles of Amendment, dated November 9, 1994
(Exhibit 3-C to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
D. Articles of Amendment, dated December 9, 1994
(Exhibit 3-D to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
E. Articles of Correction, dated January 17, 1995
(Exhibit 3-E to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
F. Articles of Amendment, dated January 13, 1995
and filed January 17, 1995 (Exhibit 3-F to
Form 10-K for the year ended December 31, 1994,
File No. 1-3375)......................................... #
G. Articles of Amendment dated March 31, 1995
(Exhibit 3-G to Form 10-Q for the quarter
ended March 31, 1995, File No. 1-3375)................... #
H. Articles of Correction - Amendment to Statement
filed March 31, 1995, dated December 13, 1995
(Filed herewith)......................................... 71
I. Articles of Amendment dated December 13, 1995
(Filed herewith)......................................... 72
J. Copy of By-Laws of the Company as revised and
amended thru December 15, 1993 (Exhibit 3-AZ to
Form 10-K for the year ended December 31, 1993,
File No. 1-3375)......................................... #
4. Instruments Defining the Rights of Security
Holders, Including Indentures
A. Indenture dated as of January 1, 1945, from the
South Carolina Power Company (the "Power Company")
to Central Hanover Bank and Trust Company, as
Trustee, as supplemented by three Supplemental
Indentures dated respectively as of May 1, 1946,
May 1, 1947 and July 1, 1949 (Exhibit 2-B to
Registration No. 2-26459)................................ #
B. Fourth Supplemental Indenture dated as of April 1,
1950, to Indenture referred to in Exhibit 4A,
pursuant to which the Company assumed said
Indenture (Exhibit 2-C to Registration No. 2-26459)...... #
C. Fifth through Fifty-second Supplemental Indentures
to Indenture referred to in Exhibit 4A dated as
of the dates indicated below and filed as
exhibits to the Registration Statements and
1934 Act reports whose file numbers are set
forth below.............................................. #
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
# Incorporated herein by reference as indicated.
68
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
4. (continued)
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-Q to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 4-C to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 4-C to Registration No. 33-38580
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
June 1, 1986 Exhibit 4-D to Registration No. 33-49421
February 1, 1987 Exhibit 4-D to Registration No. 33-49421
September 1, 1987 Exhibit 4-D to Registration No. 33-49421
January 1, 1989 Exhibit 4-D to Registration No. 33-49421
January 1, 1991 Exhibit 4-D to Registration No. 33-49421
February 1, 1991 Exhibit 4-D to Registration No. 33-49421
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
D. Indenture dated as of April 1, 1993 from South Carolina
Electric & Gas Company to NationsBank of Georgia, National
Association (Filed as Exhibit 4-F to Registration
Statement No. 33-49421)......................................... #
E. First Supplemental Indenture to Indenture referred to
in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-49421)......................... #
F. Second Supplemental Indenture to Indenture referred to
in 4-D dated as of June 15, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-57955)......................... #
9. Voting Trust Agreement
Not Applicable
10. Material Contracts
A. Copy of Supplemental Executive Retirement Plan
(Exhibit 10-A to Form 10-K for the year ended
December 31, 1980)............................................ #
11. Statement Re Computation of Per Share Earnings
Not Applicable
# Incorporated herein by reference as indicated.
69
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
12. Statement re Computation of Ratios (Filed herewith)........ 74
13. Annual Report to Security Holders, Form 10-Q or
Quarterly Report to Security Holders
Not Applicable
16. Letter Re Change in Certifying Accountant
Not Applicable
18. Letter Re Change in Accounting Principles
Not Applicable
21. Subsidiaries of the Registrant
Not Applicable
22. Published Report Regarding Matters Submitted to
Vote of Security Holders
Not Applicable
23. Consents of Experts and Counsel
Consent of Deloitte & Touche LLP.......................... 78
24. Power of Attorney
Not Applicable
27. Financial Data Schedule
Filed herewith
28. Information from Reports furnished to State
Insurance Regulatory Authorities
Not Applicable
99. Additional Exhibits
Not Applicable
# Incorporated herein by reference as indicated.
70