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, 19931995
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 Stock 8.72% Cumulative Preferred
Stock par value $50 per shareStock par value $50
share per share
8.12% Cumulative Preferred Stock 7.70% Cumulative Preferred
Stock par value $100 per shareStock 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. [x][ ]
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant. The aggregate market value
shall be computed by reference to the price at which the stock
was sold, or the average bid and asked prices of such stock, as
of a specified date within 60 days prior to the date of filing.
(See definition of affiliate in Rule 405.)
Note. If a determination as to whether a
particular person or entity is an affiliate cannot be
made without involving unreasonable effort and expense,
the aggregate market value of the common stock held by
non-affiliates may be calculated on the basis of
assumptions reasonable under the circumstances,
provided that the assumptions are set forth in this
form.
The aggregate market value of the voting stock held by nonaffiliatesnon-
affiliates of the registrant as of February 28, 199429, 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 28, 199429, 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 .......................................... 1819
Item 3. Legal Proceedings ................................... 2021
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 2021
PART II
Item 5. Market for Registrant's Common Stock
and Related Security Holder Matters ................ 2021
Item 6. Selected Financial Data ............................. 2122
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations....... 22Operations ...... 23
Item 8. Financial Statements and Supplementary Data ......... 2830
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 6055
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 6055
Item 11. Executive Compensation .............................. 6660
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 7364
Item 13. Certain Relationships and Related Transactions ...... 7365
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 7465
SIGNATURES ........................................................ 7566
3
DEFINITIONS
The following abbreviations used in the text have the meaning set
forth below unless the context requires otherwise:
ABBREVIATION TERM
AFC......................... Allowance for Funds Used During Construction
Affiliate................... Wholly-owned subsidiary of SCANA Corporation
BTU......................... British Thermal Unit
Circuit Court............... South Carolina Circuit Court
Clean Air Act............... Clean Air Act Amendments of 1990
Company..................... South Carolina Electric & Gas Company
Consumer Advocate........... Consumer Advocate of South Carolina
Dekatherm................... 1One 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 Pipe LinePipeline 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
OrganizationORGANIZATION
The Company, a wholly owned subsidiary of SCANA, is a South
Carolina corporation organized in 1924 and has its principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Company had 4,1663,721
full-time, permanent employees as of December 31, 19931995 as
compared to 4,1684,009 full-time, permanent employees as of December
31, 1992.1994.
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 and Service AreaINDUSTRY 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
in that, generally,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 2930 of the 46 counties
in South Carolina and covers more than 19,00020,000 square miles. Total estimatedThe
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, 1993, 19921995, 1994 and 19911993 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 19941996 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 32%
excluding77%, 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.
The Company recovers the costs of providing services through
rates charged to customers. Rates for regulated services are
based on historical costs. As inflation occurs and the Company
expands its construction program it is necessary to seek
increases in rates, and on June 7, 1993 the PSC issued an order
granting the Company a 7.4% annual increase, based on a test
year, in retail electric rates to be implemented in two phases of
$42.0 million annually effective June 1993 and $18.5 million
annually effective June 1994. The Company's future financial
position and results of operations will be affected by its
ability to obtain adequate and timely rate relief. (See
"Regulation.")6
The Company's estimates of its cash requirements for
construction and nuclear fuel expenditures, which are subject to
continuing review and adjustment, for 19941996 and the four-year
period 1995-19981997-2000 as now scheduled, are as follows:
Type of Facilities 1994 1995-19981997-2000 1996
(Thousands of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $245,039$268,987 $ 539,18049,036
Transmission. . . . . . . . . . . . . . . 21,230 94,17792,502 17,976
Distribution. . . . . . . . . . . . . . . 58,178 295,523319,092 64,227
Other . . . . . . . . . . . . . . . . . . 12,815 42,97534,152 13,835
Nuclear Fuel. . . . . . . . . . . . . . . . 28,064 84,77086,413 21,147
Gas . . . . . . . . . . . . . . . . . . . . 15,814 62,276
Transit . . . . . . . . . . . . . . . . . . 422 74994,147 16,918
Common. . . . . . . . . . . . . . . . . . . 30,650 54,715
Nonutility34,089 34,633
Other . . . . . . . . . . . . . . . . 139 545. . . 1,511 553
Total . . . . . . . . . . . . . . $412,351 $1,174,910$930,893 $218,325
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program
for the periods 19941996 and 1995-19981997-2000, 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 in Orangeburg
County.Carolina.
Construction of the plant started in November 1992. Commercial
operation began in November 1992 with
commercial operation expected in late 1995 or earlyJanuary 1996. The estimated pricecost of the Cope plant,
excluding financing costs
and AFC, but including an allowance for escalation, is $450$410.9 million. In addition, the
transmission lines for interconnection with the Company's system
are expected to cost $26$22.5 million. The steam generators at Summer Station will be replaced
during the 1994 regularly scheduled refueling outage. In January
1994 the Company, acting on behalf of itself and the PSA (as co-
ownersApproximately $9.8 million of the 885 Megawatt Summer Station), reached a settlement
with Westinghouse Electric Corporation (Westinghouse) resolving a
dispute involving steam generators provided by Westinghouseamounts
included in the above table for 1996 relate to Summer Station which are defective in design, workmanship and
materials. Termsthe completion of
the settlement are confidential by agreement
of the parties and order of the court. The Company had filed an
action in May 1990 against Westinghouse in the U. S. District
Court for South Carolina; an order dismissing this suit was
issued on January 12, 1994.
6
Cope plant.
During 19931995 the Company expended approximately $20$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 19941996 are estimated to cost
approximately $17$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 12twelve
consecutive months out of the 15fifteen months prior to the month
of issuance isare at least twice the annual interest requirements
on all Class A Bonds to be outstanding (Bond Ratio). For the
year ended December 31, 19931995 the Bond Ratio was 3.70.3.97. The
issuance of additional Class A Bonds also is restricted also to an
additional principal amount equal to (i) 60% of unfunded net
property additions (which unfunded net property additions totaled
approximately $219.9$162.3 million at December 31, 1993)1995), Class A Bonds issued on the
basis of(ii)
retirements of Class A Bonds (which retirement credits totaled
$10.9$64.8 million at December 31, 1993)1995), (iii) and Class A Bonds
issued on the basis of cash on deposit
with the Trustee.
The Company has placed a new bond indenture (New Mortgage)
dated April 1, 1993 oncovering substantially all of its electric
properties under which its future mortgage-backed debt (New
Bonds) will be issued. New Bonds are expected to be issued under the New
Mortgage on the basis of a like principal amount of Class A Bonds
issued under the Old Mortgage which have been deposited with
the Trustee of the New Mortgage (of which $157$185 million were
available for such purpose as ofat December 31, 1993)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 12twelve consecutive months out of the
18eighteen 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,
19931995 the New Bond Ratio was 5.0.5.31.
The following additional financing transaction has occurred
since December 31, 1994:
On April 29, 199312, 1995 the Securities and Exchange Commission
declared effective a registration statement for the issuance of
up to $700Company issued $100 million of New Bonds. The following series,
aggregating $600 million, have been issued under such
registration statement:
On June 9, 1993, $100 million,First
Mortgage Bonds, 7 5/8% Seriesseries due JuneApril 1, 20232025 to repay
short-term borrowings in a like
amount.
On July 1, 1993, $100 million, 6% Series due
June 15, 2000, and $150 million, 7 1/8% Series due
June 15, 2013, and on July 20, 1993, $150 million,
7 1/2% Series due June 15, 2023, to redeem, on
July 20, 1993, $382,035,000 of First and Refunding
Mortgage Bonds maturing between 1999 and 2017 and
bearing interest at rates between 8% and 9 7/8% per
annum.
On December 20, 1993. $100 million, 6 1/4% Series due
December 15, 2003 to repay short-term borrowings in a
like amount.
On June 1, 1993 the Company redeemed the following
amounts of First and Refunding Mortgage Bonds:
$35 million, 10 1/8% Series due 2009 and $13 million,
9 7/8% Series due 2009.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 indebted-
ness.debt.
The FERC has authorized the Company to issue up to $200 million
of unsecured promissory notes or commercial paper with maturity
dates of 12twelve months or less, but not later than December 31,
1995.
7
1997.
The Company has $127.0had $165 million authorized and unused lines of
credit at December 31, 1993.
SCE&G's1995. 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 12twelve consecutive months immediately preceding
the month of issuance isare 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, 19931995 the Preferred Stock Ratio was 2.52.2.58.
8
The ratioratios of earnings to fixed charges (SEC Method) waswere
3.41, 3.46, 3.57, 2.73 3.32, 3.33 and 3.043.32 for the years ended December 31,
1995, 1994, 1993, 1992 and 1991, 1990 and 1989, respectively.
Additional Capital Requirements
In additionThe Company expects that it has or can obtain adequate
sources of financing to the Company's capitalmeet its projected cash requirements for
1994
described above, approximately $5.0 million will be requiredthe next twelve months and for refunding and retiring outstanding securities and obligations.
For the years 1995-1998, the Company has an aggregate of $149.4
million of long-term debt maturing (including approximately $43.9
million for sinking fund requirements, of which $43.5 million may
be satisfied by deposit and cancellation of bonds issued upon the
basis of property additions or bond retirement credits) and $9.9
million of purchase or sinking fund requirements for preferred
stock.
Actual 1994 expenditures may vary from the estimates set
forth above due to factors such as inflation, economic
conditions, regulation, legislation, rates of load growth,
environmental protection standards and the cost and availability
of capital.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 fuel.fuels. To
finance nuclear and fossil fuel inventories,fuels and sulfur dioxide emission
allowances, Fuel Company issues, from time to time, its promissory notes with maturities of less than
270 days ("Commercial Paper"). The issuance of Commercial Papercommercial
paper which is supported, up to $125 million, by an irrevocable
revolving credit agreement which expires July 31, 1996 and is guaranteed by the Company.1998.
Accordingly, the amounts outstanding have been included in long-
term debt. TheThis commercial paper and amounts outstanding under
the revolving credit agreement, provides for a maximum amount of
$75 million that may be outstanding atif any, time.are guaranteed by the
Company.
At December 31, 1993 Commercial Paper1995 commercial paper outstanding for
nuclear and fossil fuel inventories was
approximately $36.8$76.8 million at a weighted average interest
rate of 3.47%5.76%. Such
fuel inventories and fuel-related assets and liabilities are
included in the Company's financial statements. (See Notes 11N and 4 of Notes to Consolidated
Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 19931995 residential sales of electricity accounted for 43%
of electric sales revenues; commercial sales 29%30%; industrial
sales 21%20%; sales for resale 4%; and all other 3%. KWH sales by
classification for the years ended December 31, 19931995 and 19921994 are
presented below:
Sales
KWH %
Classification 1993 19921995 1994 Change
(thousands)
Residential 5,650,759 5,155,886 9.505,726,815 5,311,139 7.83
Commercial 4,844,422 4,538,862 6.735,078,185 4,848,620 4.73
Industrial 4,887,250 4,684,072 4.345,210,368 5,161,717 0.94
Sale for resale 1,005,968 946,357 6.301,063,064 1,024,376 3.78
Other 500,937 476,064 5.22506,806 494,030 2.59
Total Territorial 16,889,336 15,801,241 6.8917,585,238 16,839,882 4.43
Interchange 198,059 77,046 157.07195,591 171,046 14.35
Total 17,087,395 15,878,287 7.61
8
17,780,829 17,010,928 4.53
The Company furnishes electricity for resale to three
municipalities, threefour investor-owned utilities, two electric
cooperatives and one public power authority. Such sales for
resale accounted for 4% of total electric sales revenues in 1993.
An addition1995.
During 1995 the Company recorded a net increase of 6,9737,943
electric customers, to 468,901increasing its total customers contributed to an484,381.
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 record of 3,557
on July 29, 1993. The previous years' record of 3,3803,683
MW was set July 13, 1992.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 portionportions 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
whichCouncil.
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 1991-1993.
1991 19921993-1995.
1995 1994 1993
Nuclear:
Per million BTU $ .57.48 $ .52.51 $ .47
Coal:
Company:
Per ton $41.61 $40.00$40.01 $39.92 $39.95
Per million BTU 1.63 1.561.57 1.57 1.55
GENCO:
Per ton $42.12 $41.82$42.21 $41.85 $41.64
Per million BTU 1.641.63 1.63 1.62
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.381.26 $ 1.271.39 $ 1.331.31
The fuel costs shown above exclude the effects of a PSC
approvedPSC-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 1991-19931993-1995 and the
estimates for 19941996 and 1995.1997.
Percent of Total KWH Generated
Estimated Actual
Estimated
1991 19921997 1996 1995 1994 1993
1994 1995
Coal 68%73% 71% 65% 76% 72%
77% 69%
Nuclear 21 29 2224 24 27 17 2623
Hydro 3 3 5 5 5 56 5
Natural Gas & Oil 6 1 1- 2 3 1 -
100% 100% 100% 100% 100%
Coal is currently used at all fourfive of the Company's major fossil fuel-firedfuel-
fired plants and GENCO's Williams Station. Unit train deliveries
are used at all of these plants. On December 31, 19931995 the
Company had approximately a 73-day supply of coal in inventory
and GENCO had approximately a 56-day49-day supply.
9
The supply of coal is obtained through contracts and
purchases on the spot market. Spot market purchases are expected
to continue for coal requirements in excess of those provided by
the Company's existing contracts. Contracts for the purchase
of coal represent the following percentages91.5% of estimated requirements for 19941996
(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 dates
indicated (giving effectcontract coal range from .75% to the Company's potential to exercise
renewal options):
Range of % of Final
No. of Tons % of 1994 Sulfur Content Expiration Renegotiation
Per Year Requirement per Contract Date (1) Date (1)
966,664 18.2 up to 1.55 02/28/2001 02/28/1995
360,000 6.8 1.00 - 1.80 12/31/2002 12/31/1996
134,000 2.5 1.10 - 2.00 03/31/1996 03/31/1994
120,000 2.3 1.10 - 1.60 04/30/1996 04/30/1994
972,000 18.3 up to 1.50 12/31/2002 12/31/1996
192,832 3.6 0.80 - 1.50 06/30/2000 06/30/1994
2,745,496 51.7
(1) Contract extensions beyond the stated renegotiation date to
the final expiration date are subject to mutual agreement on
price, terms, quantity and quality.
All of the above contracts, except the contracts expiring in
March 1994 and April 1994 which have firm prices, are subject to
periodic price adjustments based on changes in indices published
by the U. S. Department of Labor.
Coal purchased in December 1993 had an average sulfur
content of 1.17%, which permitted the Company to comply with
existing environmental regulations.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.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 Control Matters").
The Company currently has adequate supplies of uranium under contract
to manufacture nuclear fuel for Summer Station through 1996.2005. The
following table summarizes all contract commitments for the
stages of nuclear fuel assemblies:
Commitment Contractor Regions(1) Term
Uranium NUEXCO Trading
Corporation 11 1994
Uranium Energy Resources
of Australia 9-13 1990-19961990-1997
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995
Enrichment DOE (2) Through 2022USEC 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.
1011 was loaded in 19931994 and regionRegion no. 1112 will be loaded in
1994.
(2) The contract with the DOE is a "requirements" type
contract whereby the DOE supplies total enrichment
requirements for the unit through the year 2022, as
specified by its then current schedule.1996.
11
The Company has on-site spent nuclear fuel storage
capability until at least 20082009 and expects to be able to expand
its storage capacity over the life of Summer Station to accommodate the spent fuel output for the
life of the plant through rod consolidation, dry cask storage or
other technology as it becomes available. In addition, there is
sufficient on-site storage capacity over the life of Summer
Station to permit storage of the entire reactor core in the event
that complete unloading should become desirable or necessary for
any reason. (See "Nuclear Fuel Disposal" under "Environmental
Control Matters" for information regarding the contract with the DOE for
disposal of spent fuel.)
10
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 19931995 residential sales accounted for 36%47% of gas sales
revenues; commercial sales 26%32%; industrial sales 17% and
transportation gas 21%.
Dekatherm sales by classification for the years ended December
31, 19931995 and 19921994 are presented below:
SALES
DEKATHERMSSales
Dekatherms %
CLASSIFICATION 1993 1992 CHANGEClassification 1995 1994 Change
Residential 12,009,444 11,286,08812,333,769 11,531,558 7.0
Commercial 10,436,987 9,813,454 6.4
Commercial 8,842,728 9,029,256 (2.1)
Industrial 5,881,309 5,334,117 10.313,467,687 10,938,713 23.1
Transportation gas 6,993,817 5,906,697 18.43,603,314 5,469,728 (34.1)
Total 33,727,298 31,556,158 6.939,841,757 37,753,453 5.5
During 19931995 the Company added 2,696recorded a net increase of 4,909 gas
customers, increasing its total customers to 221,278.243,342.
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 alternativealternate fuels and other
factors.
12
The deregulation of natural gas prices at the wellhead which
took place on January 1, 1985 and
the changes in the prices of natural gas that have occurred under
Federal regulation have resulted in the development of a spot
market for natural gas in the producing areas of the country.
Pipeline Corporation has been successful in purchasing lower cost
natural gas in the spot market and arranging for its
transportation to South Carolina.
On April 8, 1992, the FERC promulgated itsNovember 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which is intended to deregulatederegulated the markets for interstate sales of
natural gas by requiring that pipelines provide transportation
services that are equal in quality for all gas supplies whether
the customer purchases gas from the pipeline or another supplier.
The impact of this order on the Company will be primarily through
changes affecting its supplier, Pipeline Corporation, which,
while operating wholly within the state of South Carolina, is
served by two interstate pipelines.Corporation.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for the purchase of alternate fuel vehicles for federal,on
Federal, state, municipal and private fleets which increase over a period of
years.fleets. The Company
expects these requirements for alternate fuel
vehicles to develop business opportunities for
the sale of compressed natural gas as fuel for vehicles, but it
cannot predict the extentmagnitude of this new market.
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts
with producers brokers and interstate pipelines.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 contractstransportation agreements with both
Southern Natural and Transco.Transco, which expire at various times from
1996 to 2003. The volume of gas which Pipeline Corporation is
entitled to transport throughunder these contracts on a firm basis is
shown below:
Maximum Daily
Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 160,000184,974
Transco Firm Transportation 29,90029,300
Total 189,900
11
214,274
Under a contract with Pipeline Corporation, the Company's
maximum daily contract demand is 184,000 MCF.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 $3.81$3.77 in 19931995 compared to
$3.65$4.29 in 1992.1994.
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 storage tanksplants are capable of storing the liquefiedlique-
fied equivalent of 1,900,000 MCF of natural gas, of which
approximately 1,450,0001,695,489 MCF were in storage at December 31, 1993.1995.
On peak days the LNG plants can regasify up to 150,000 MCF per
day. Additionally, Pipeline Corporation had contracted for
6,398,0356,450,727 MCF of natural gas storage space on December 31, 1993,
of which 4,880,4844,307,796 MCF
were in storage at such date. Propane
air peak shaving facilities located in the Company's
service area can supply an additional 137,400 MCF per day.on December 31, 1995.
The Company believes that Pipeline Corporation's current
supplies under contract and
available for spot market purchase of natural gas are adequate to meet existing
customer demands for service 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 regulatory
jurisdictionregulation under
the Federal Power Act, administered by the FERC and the DOE, in
the transmission of electric energy in interstate commerce and in
the sale of electric energy at wholesale for resale, as well as
with respect to licensed hydroelectric projects and certain other
matters, including accounting and the issuance of short-term
promissory notes.
National Energy Policy Act of 1992
Congress has passed NEPA, the principal thrust of which is
to create a more competitive wholesale power supply market by
creating "exempt wholesale generators" (EWGs) designated by the
FERC, which are independent power producers (IPPs) whose owners
will not become holding companies under PUHCA. Upon application
of a wholesaler of electric energy, the FERC may order an
electric utility that owns transmission facilities used for
wholesale sales of electric energy to provide transmission
service (including any enlargement of transmission capacity
needed to provide the service) to the applicant. Charges for
transmission service must be "just and reasonable" and a utility
is entitled to recover "all legitimate, verifiable economic
costs" incurred in connection with any transmission service so
ordered. The FERC may not order such service where it (1) would
"unreasonably impair the continued reliability of electric
wheeling" judged by reference to "consistently applied regional
or national reliability standards, guidelines or criteria;" (2)
would result in "retail wheeling;" or (3) would conflict with
state laws governing retail marketing areas of electric
utilities. Electric utilities, including exempt and non-exempt
holding companies, may own and operate EWGs subject to advance
approval by state utility commissions, which are given access to
books and records of the EWG and its affiliates to the extent
that such a commission requires access to perform its
regulatory duties. It allows both registered and exempt
12
utility holding companies to acquire interests in foreign utility
companies engaged in the generation, transmission or distribution
of electricity or the retail distribution of gas, where a state
commission has certified that it has the ability to protect the
utility's retail ratepayers against adverse investments in
foreign utilities by affiliates of public utilities that such
commissions regulate. State Commissions must consider rate
making changes and other regulatory reform to ensure that
electric utilities' investments in energy efficiency and demand
side management programs are at least as profitable as investing
in new generating capacity. FERC has issued a Notice of Proposed
Rule Making to develop regulations under NEPA concerning EWGs and
electric transmission service.
NEPA also has provisions concerning nuclear power, alternate
fuel vehicles, minimum efficiency standards, integrated resource
planning, demand side management incentives, a variety of energy
research projects relating to environmental measures, electric
and magnetic fields, hydroelectric projects, and global warming.
It authorizes one step licensing for nuclear power plants and
requires EPA to issue standards for the Yucca Mountain repository
site for nuclear waste (see "Nuclear Fuel Disposal" under
"Environmental Control Matters"). To reduce dependence on
imported oil, NEPA imposes purchase requirements for alternate
fuel vehicles for federal, state, municipal and private fleets
which increase over a period of years (see "Gas Operations").
In the opinion of the Company, it will be able to meet
successfully the challenges of an altered business climate for
electric and gas utilities and natural gas businesses. Neither
the application of NEPA or FERC Order No. 636 nor the development
of an EWG industry, new markets and obligations for transmission
services for wholesale sales of electricity, nor deregulated
interstate natural gas markets is expected to have awithout any material
adverse impact on theits results of its operations, its financial position
or its business prospects.
Federal Energy Regulatory Commission
PursuantThe Company is subject to Section 204 ofregulation under the Federal Power
Act, administered by the Company must obtain FERC authorityand 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 issuelicensed hydroelectric projects and certain other matters
including accounting and the issuance of short-term indebtedness. The FERC has authorized the Company to issue up to
$200 million of unsecured promissory
notes or commercial paper
with maturity dates of 12 months or less but not later than
December 31, 1995.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 KW capability) and5,000 1993
Stevens Creek (9,000 KW capability) 1993;9,000 2025
Columbia (10,000 KW
capability) 2000;10,000 2000
Saluda Project (206,000 KW capability) 2007;
and206,000 2007
Parr Shoals (14,000 KW capability) and14,000 2020
Fairfield Pumped Storage Project (512,000 KW capability) 2020.512,000 2020
Pursuant to the provisions of the Federal Power Act, as
amended, by the Electric
Consumers Protection Act of 1986, applications for new licenses 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 was accepted for
filing byis in the FERC on September 30, 1992 and the Stevens Creek
application was accepted September 15, 1993.final stage of review.
The FERC has issued Noticesa Notice of Authorization for Continued
Project Operation for both
projects until FERC has acted on SCE&G's applications for new
licenses. FERC has announced its intentions to perform a
Multiple-project Environmental Assessment for Neal Shoals anduntil the FERC acts on the
Company's application for a Multiple-project Environmental Impact Statement for Stevens
Creek.new license.
At the termination of a license under the Federal Power Act,
the United States Governmentgovernment 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 shallis entitled to be paid its net investment in the
project, (notnot to exceed fair value)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. The NRC conducts semiannual reviews
that identify plants that have demonstrated an excellent level of
safety performance. Summer Station was recognized in both 1993
reviews as one of the top nuclear plants in the country.
In addition, the Federal Emergency
Management Agency is responsible for the review, in conjunction
with the NRC, of certain aspects of emergency planning relating
to the operation of nuclear plants.
13
RATE MATTERS
The following table presents a summary of significant rate activity for
the years 1990-1993 based on test years:
REQUESTED GRANTED
Date of
General Rate Application/ Amount % Increase Date of Amount % of Increase
Applications Hearing (Millions) Requested Order (Millions) Granted
PSC
Electric
Retail 01/03/89 $ 27.2 3.7% 07/03/89 $18.2* 67%*
Retail 12/07/92 $ 72.0** 11.4% 06/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%
*Reflects a rate reduction of $3.7 million on January 4, 1993 (see
discussion below) and excludes impact* As modified to reflect lowering of rate reduction of $7.7
million onreturn 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 3, 1990 which corresponds to $7.7 million reduction
in cost-of-service resulting from NRC approval of extension of Summer
Station's operating life to 40 years.
** As modified
On June 7, 19939,
1996 the PSC issued an order ongranting the Company's pending
electric rate proceeding allowingCompany an authorized return on common
equityincrease of
11.5%, resulting7.34% which will produce additional revenues of approximately
$67.5 million annually. The increase will be implemented in a 7.4% annualtwo
phases. The first phase, an increase in retail
electric rates, or a projected $60.5revenues of
approximately $59.5 million annually based on a test year. These rates are toyear, or
6.47%, commenced on January 15, 1996. The second phase will
be implemented in two phasesJanuary 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 two-year
period: phase one, effective June 1993, producing $42.0 million
annually,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 phase two, effective June 1994, producing $18.5 million
annually, based on a test year.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 modified,
had proposed a return on equityresult of 12.05% and had projectedthe ongoing annual increasesreview, the PSC approved
the continued use of $53.0 million and $19.0 million for phases one and two,
respectively.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 incomelow-income customers and denied the
Company's request to reduce the number of routes and frequency of
service. The new rates were placed into effect on October 5,
1992. The Company has appealed the PSC's order to the Circuit
Court. During oral arguments in
February 1994On May 23, 1995 the Circuit Court retained jurisdiction and remandedordered the decisioncase back
to the PSC for reconsideration of several issues including the
limited purpose of answering questions
concerninglow-income rider program, routing changes, and the applicable regulatory principles used by the PSC in
determining these transit rates.
Since November 1, 1991 the Company's gas rate schedules for its
residential, small commercial and small industrial customers have
included a weather normalization adjustment (WNA). The WNA minimizes
fluctuations in gas revenues due to abnormal weather conditions and
has been approved through November 1994 subject to an annual review by
the PSC. The PSC order was based on a return on common equity of
12.25%. The WNA became effective the first billing cycle in December
1991.
In May 1989 the PSC approved a volumetric and direct billing
method for Pipeline Corporation to recover take-or-pay costs incurred
from its interstate pipeline suppliers pursuant to FERC-approved final
and non-appealable settlements. In December 1992 the Supreme Court
approved Pipeline Corporation's full recovery of the take-or-pay
charges imposed by its suppliers and treatment of these charges as a
cost of gas. However, the Supreme Court declared the PSC-approved
"purchase deficiency" methodology for recovery of these costs to be
unlawful retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. The Company believes that the
elimination of the purchase deficiency method of recovery will affect
the timing for recovery of take-or-pay charges and shift the
allocations among Pipeline Corporation's customers (including the
Company) but that all such charges should be ultimately recovered.$.75 fare.
The Supreme Court declined to review an appeal of the Circuit
Court decision establishes a principle of law that will
provide a basisand dismissed the case. The PSC filed, along with
other intervenors, another Petition for full recovery byReconsideration, which
the Company, as well as Pipeline
Corporation, of these costs.
14
On July 3, 1989 the PSC granted the Company approximately $21.9
million of a requested $27.2 million annual increaseCircuit Court denied. Procedural matters in retail
electric revenues based upon an allowed return on common equity of
13.25%. The Consumer Advocate appealed the decisionthis case are
yet to the Supreme
Court which, on August 31, 1992, found that the evidencebe resolved in the record of that case did not support a return on common equity
higher than 13.0% and remanded to the PSC a portion of its July
1989 order for a determination of the proper return on common
equity consistent with the Supreme Court's opinion. On January 19,
1993 the PSC issued an order allowing a return on common equity of
13.0%, approving a refund based on the difference in rates created
by the difference between the 13.0% and the 13.25% return on common
equity and making other non-material adjustments to the calculation
of cost-of-service. The total refund before interest and income
taxes, was approximately $14.6 million and was charged against 1992
"Electric Revenues." The refund plus interest was made during
1993.
On November 28, 1989 the PSC granted the Company an increase in
firm retail natural gas rates, effective November 30, 1989,
designed to increase annual revenues by $10.1 million, or 89.5%
out of the requested increase of approximately $11.3 million. In
its order the PSC authorized a 12.75% return on common equity. The
Consumer Advocate appealed to the Supreme Court which on August 31,
1992 remanded the order to the PSC for redetermination of the
proper amount of litigation expenses to include in the test period.
In January 1993 the PSC reduced the amount of litigation expense
and ordered a refund totaling approximately $163,000 which was
charged against 1992 "Gas Revenues." The refund was made during
1993.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 19931995 semiannual review of the fuel cost
component of electric rates, the PSC voted to reducedecreased the rate from
13.514.16 mills per KWH to 13.013.48 mills per KWH, a monthly decrease of
$.50$.68 for an average customer using 1,000 KWH a month. This reduction coincided
with the retail electric rate case effective June 1993. For the
October 19931995 review the PSC voted to continuecontinued the rate of 13.013.48 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 19931995 review the PSC authorized an increase indecreased the base cost
of gas from 41.96351.058 cents per therm to 47.10043.081 cents per therm
which resulted in a monthly increasedecrease of $5.14$7.98 (including
applicable taxes) based on an average of 100 therms per month on
a residential bill during the heating season.
In July 1990 the PSC initiated proceedings for a generic
hearing on the Industrial Sales Program Rider (ISPR) for the
Company and Pipeline Corporation. The PSC issued an order dated
December 20, 1991 approving a Stipulation and Agreement signed in
December 1991 by all parties involved which retained the ISPR with
modifications to Pipeline Corporation's gas cost mechanisms.
1516
ENVIRONMENTAL CONTROL MATTERS
General
Federal and state authorities have imposed environmental
control requirements relating primarily to air emissions,
wastewater discharges and solid, toxic and hazardous waste
management. The Company is attempting to ensure that its
operations meet applicable environmental regulations and standards.
It is difficult to forecast the ultimate effect of environmental
quality regulations upon the existing and proposed operations.
Moreover, developmentsDevelopments in these and other 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 19911993 through 1993,1995, capital expenditures for
environmental control amounted to approximately $73.6$90.0 million.
In addition, approximately $7.4$10.4 million, $5.7$8.8 million and $4.8$7.4
million of environmental control expenditures were made during
1993, 19921995, 1994 and 1991,1993, 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 minimum
capitalized expenditures are $40.3$10.1 million for 19941996
and $252.1$138.8 million for the four-year period 19951997 through 1998.2000.
These expenditures are included in the Company's construction
program.
Air Quality Control
The Federal Clean Air Act requires electric utilities to reduce
substantially emissions of 1970 (the "1970 Act") requires
that electric generating plants comply with primary and secondary
ambient air quality standards with respect to certain air
pollutants including particulates, sulfur oxidesdioxide and nitrogen oxides and imposes economic penalties for noncompliance. This Act
was amended withoxide by
the passage of the Clean Air Act Amendments of
1990.
Currently, the Company uses a variety of methods to comply
with the State Implementation Plan (developed pursuant to the 1970
Act), including the use of low sulfur fuel, fuel switching,
reduction of load during periods when compliance cannot be met at
full power, maintenance and improvement of existing electrostatic
precipitators and the installation of new baghouses.year 2000. These requirements are being phased in over two
periods. The Company
and GENCO have been able to purchase sufficient fuel meeting
current sulfur standards for all of their plants. With respect to
sulfur dioxide emissions, none of the Company's electric
generating plants is included among the Phase I plants listed in
the Clean Air Act Amendments of 1990 withfirst phase had a compliance date of January 1,
1995. Both companies will, however, be affected by
Phase II requirements which have a compliance date of1995 and the second, January 1, 2000. The companies undertook a study in 1992 to determine the
most cost effective mix of control optionsCompany's facilities
did not require modifications to meet the requirements of the Clean Air Act. Such a control strategyPhase
I. The Company will most likely result in requiringmeet the Company to utilize a combinationPhase II requirements
through the burning of the
following alternatives to meet its compliance requirements: (1)
burnnatural gas and/or lower sulfur coal (2) burn natural gas, (3) retrofit at least
one coal-fired electricin
its generating unit with a scrubber to remove
sulfur dioxideunits and (4)the purchase and use of sulfur dioxide
emission allowances
to the extent necessary. In addition, the Company will install on
most of its coal-fired units lowallowances. Low nitrogen oxide burners are being
installed to reduce nitrogen oxide emissions.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 excluding GENCO, air emissions control equipment will
require capital expenditures of $190$113 million over the 1994-19981996-2000
period to retrofit existing facilities, and anwith increased operation
and maintenance cost of $22approximately $1 million per year. Total capital expenditures required toTo
meet compliance requirements through the year 2003 are anticipated to be2005, the Company
anticipates total capital expenditures of approximately $211$150
million.
16
Water Quality Control
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a
national permit program. Discharge permits have been issued for
all and renewed for nearly all of the Company's and GENCO's
generating units. CommensurateConcurrent with renewal of these permits the
permitting agency has been implementation
ofimplemented a more rigorous control
program on behalf of the permitting
agency.program. The facilities haveCompany has been developing compliance plans to
meet the additional parameters of control and compliance has
involved updating wastewater treatment technologies.this program. Amendments to the Clean Water Act proposed recently 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-
basedtechnology-based standards.
17
Superfund Act and Environmental Assessment Program
As described in Note 1L of Notes to Consolidated Financial
Statements, theThe 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 isestimates are made of the amount of expenditures,cost, 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 differ from the original estimates.
Amounts estimated and accrued to date ($19.6 million) for site assessments and
cleanup relate primarily to regulated operations; such amounts
have beenare deferred and are being amortized and recovered through rates
over a ten-year period.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 to
date include, among other things,items, the costs
estimated to be associated with the matters discussed in the
following paragraphs.
The Company and SCANA each own twoowns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company and SCANA have eachhas maintained an active review of their respectivethe 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 18eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority List, but may
be added before cleanup is initiated. The potentially responsible parties (PRP)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 (RI/FS) and a corresponding Scope
of Work. Actual fieldField work began in November 1, 1993 after final
approval and authorization was granted by EPA.1993. The Company is
also working with the City of Charleston to investigate potential
contamination from the manufactured gas plant atwhich may have
migrated to the city's aquarium site. During 1993In 1994 the City of
Charleston notified the Company settledthat 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 obligations at the Yellow
Water Road Superfund Site near Jacksonville, Florida, the Spencer
Transformer and Equipment Site in West Virginia and Elliott's Auto
Parts in Benton, Arkansas. No further expenses are anticipated for
these sites.resolution to have a material impact on its
financial position or results of operations.
The Company has been listed as a PRP and has recorded
liabilities, which are not considered material, for the Macon-
DockeryMacon-Dockery waste
disposal site near Rockingham, North Carolina,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. 17The 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 requires promulgation ofdirected the DHEC to promulgate regulations addressing specified
subjects, one of which affectsfor the managementdisposal
of industrial solid waste. ThisDHEC has promulgated a proposal
regulation, will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation,which if adopted as a final regulation in its present
form, couldwould significantly impactincrease the Company's engineering, designcosts of
construction and operation of existing and future ash management
facilities.
Potential cost impacts could be substantial.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 (the "1982 Act") requires that the
Federal GovernmentUnited 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 20082009 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 1982 Act also imposes on utilities the primary responsibility for
storage of their spent nuclear fuel until the repository is
available. (See "Fuel Supply" under "Electric
Operations" for a discussion of spent fuel storage facilities at
Summer Station.)
OTHER MATTERS
With regard to the Company's insurance coverage for Summer
Station, reference is made to Note 10B of Notes to Consolidated
Financial Statements, which is incorporated herein by reference.Statements.
ITEM 2. PROPERTIES
Reference is made to Schedule V - Property Plant and
Equipment, pages 54 through 59, for information concerning
investments in utility plant and nonutility property.
The Company's bond indentures, securing the First and
Refunding Mortgage Bonds and First Mortgage Bonds issued
thereunder, constitute direct mortgage liens on substantially all
of its property.
1819
ELECTRIC
The following table gives information with respect to the Company's
electric generating facilities.
Net Generating
Present Year Capability
Facility Fuel Capability Location In-Service (KW)(1)
Steam
Urquhart Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 430,000
Wateree Coal Eastover, SC 1970 700,000
Summer (2) Nuclear Parr, SC 1984 590,000594,000
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 26,00038,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (3)(5) Gas/Oil Parr, SC 1970 60,000
Williams (4)(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 (5) 3,304,000(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. (4)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.
(5)(7) Excludes Williams Station.
20
The Company owns 424429 substations having an aggregate
transformer capacity of 18,624,78019,577,868 KVA. The transmission system
consists of 3,0333,090 miles of lines and the distribution system
consists of 15,18615,596 pole miles of overhead lines and 3,0063,191 trench
miles of underground lines.
GAS
Natural Gas
The Company's gas system consists of approximately 6,1796,833
miles of three-inch equivalent distribution pipelines and
approximately 10,08511,265 miles of distribution mains and related
service facilities.
The gas system acquired by SCANA is operated by the Company
and consists of approximately 450 miles of three-inch equivalent
distribution pipelines and approximately 778 miles of distribution
mains and related service facilities. Effective January 1, 1994
the assets and liabilities of such gas system were transferred from
SCANA to the Company.
19
Propane
The Company has propane air peak shaving facilities which
can supplement the supply of natural gas by gasifying propane to
yield the equivalent of 102,000 MCF per day of natural gas.
These facilities can store the equivalent of 430,405 MCF of
natural gas.
TRANSIT
The Company owns 9398 motor coaches which operate on a route
system of 285286 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 ITEMItem
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 19931995 and
19921994 the Company paid $108.6$116.7 million and $96.6$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, 19931995
approximately $10.6$14.5 million of retained earnings were restricted
as to payment of cash dividends on common stock.
2021
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1995 1994 1993 1992 1991
1990 1989
STATEMENT OF INCOME DATAStatement of Income Data (Thousands of Dollars except statistics)
Operating Revenues:
ElectricRevenues $1,211,087 $1,181,274 $1,118,433 $ 940,547 $ 829,938 $ 867,685 $ 851,676 $ 842,059
Gas 174,035 160,820 150,788 147,794 153,206
Transit 3,851 3,623 3,869 4,033 4,102
Total994,381 $1,022,342
Operating Revenues 1,118,433 994,381 1,022,342 1,003,503 999,367
Operating Expenses:
Fuel used in electric generation
and purchased power 275,298 242,122 262,756 254,489 271,936
Gas purchased for resale 107,722 95,854 93,179 94,358 107,148
Other operation and maintenance 268,233 260,098 248,601 243,735 233,068
Depreciation and amortization 101,220 97,064 91,618 87,021 92,495
Taxes 146,641 116,976 129,482 125,954 109,641
Total Operating Expenses 899,114 812,114 825,636 805,557 814,288
Operating Income 255,854 230,418 219,319 182,267 196,706
197,946 185,079
Other Income:
Allowance for equity funds used
during construction 7,496 4,577 2,966 1,308 1,931
Other (911) (1,571) 317 (2,267) 1,399
Total Other Income 9,553 7,271 6,585 3,006 3,283
(959) 3,330Net Income Before Interest Charges 225,904 185,273 199,989 196,987 188,409
Interest Charges (Credits):
Interest 85,222 86,994 81,340 79,481 78,670
Allowance for borrowed funds used
during construction (5,286) (3,884) (4,187) (3,333) (3,934)
Total Interest Charges, Net 79,936 83,110 77,153 76,148 74,736
Net Income169,185 152,043 145,968 102,163 122,836 120,839 113,673
Dividends on Preferred Stock 6,217 6,474 6,706 6,911 7,263
Earnings Available for Common Stock $163,498 146,088 139,751 $ 95,689 $ 116,130
$ 113,928 $ 106,410
BALANCE SHEET DATABalance Sheet Data
Utility Plant, Net $3,157,657 $2,998,132 $2,687,193 $2,503,201 $2,380,761
$2,270,182 $2,185,505
Total Assets $3,189,939 $2,890,953 $2,748,580 $2,625,407 $2,529,6593,802,433 3,587,091 3,189,939 2,890,953 2,748,580
Capitalization:
Common equity $1,051,334 $1,315,072 1,133,432 1,051,334 963,741 $ 840,505
$ 821,373 $ 774,909
Preferred stock:
Notstock (Not subject
to purchase or sinking fundsfunds) 26,027 26,027 26,027 26,027 26,027
SubjectPreferred stock, Net (Subject to
purchase or sinking funds, Netfunds) 46,243 49,528 52,840 56,154 59,469
62,704 66,099
Long-term debt, (excludes current portion)Net 1,279,379 1,231,191 1,097,043 945,964 993,674
779,524 802,328
Total Capitalization $2,666,721 $2,440,178 $2,227,244 $1,991,886 $1,919,675
$1,689,628 $1,669,363
OTHER STATISTICSOther Statistics
Electric:
Customers (Year-End) 484,381 476,438 468,901 461,928 453,687 446,544 435,033
Territorial Sales (Million KWH) 17,585 16,840 16,889 15,801 15,702 15,394 14,896
Residential:
Average annual use per customer (KWH) 13,859 13,048 14,077 13,037 13,246 13,330 12,891
Average annual rate per KWH $.0747 $.0743 $.0707 $.0695 $.0700
$.0707 $.0699
Gas:
Customers (Year-End) 243,342 238,433 221,278 218,582 214,485
210,326 205,471
Sales (Thousand Therms) 362,384 322,837 267,335 256,495 247,483 252,373 268,915
Residential:
Average annual use per customer (therms)(Therms) 570 538 606 577 522 497 575
Average annual rate per therm $.82 $.84 $.76 $.74 $.77 $.77 $.69
Transit:
Number of Coaches 93 95 102 109 113
Revenue Passengers Carried (Thousands) 4,568 5,837 6,395 6,788 6,430
2122
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 in Orangeburg County.Carolina. Construction of the plant started in November
1992. Commercial operation began in November 1992 with commercial operation expected in late
1995 or earlyJanuary 1996. The estimated
pricecost of the Cope plant, excluding financing costs and AFC, but including an allowance for
escalation, is $450$410.9 million. In
addition, the transmission lines for interconnection with the
Company's system are expected to cost $26$22.5 million.
Until the completion of the new plant,On July 10, 1995 the Company is contractingfiled an application with the
PSC for additional capacity as necessary to
ensure that the energy demands of its customers can be met.
As discussedan increase in Note 2A of Notes to Consolidated Financial
Statements on June 7, 1993retail electric rates. On January 9, 1996
the PSC issued an order granting the Company a 7.4% annualan increase in retail electric rates toof 7.34%
which will produce additional revenues of approximately $67.5
million annually. The increase will be implemented in two
phasesphases. The first phase, an increase in revenues of
$42.0approximately $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, effective
June 1993or .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 $18.5the 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 annually effective June 1994.of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved.
23
The estimated primary cash requirements for 1994,1996, excluding
requirements for fuel liabilities and short-term borrowings,
(including notes payable to affiliated companies), and the actual
primary cash requirements for 19931995 are as follows:
1994 19931996 1995
(Thousands of Dollars)
Property additions and construction
expenditures, excludingnet of allowance for
funds used during construction (AFC) $384,287 $280,910$197,179 $250,870
Nuclear fuel expenditures 28,064 7,17721,147 21,045
Maturing obligations, redemptions and
sinking and purchase fund requirements 5,024 3,70021,197 15,812
Total $417,375 $291,787$239,523 $287,727
Approximately 20.0%45% of total cash requirements (excluding(after payment
of dividends) was provided from internal sources in 19931995 as
compared to 49.2%22% in 1992.1994.
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 12twelve
consecutive months out of the 15fifteen months prior to the month
of issuance isare at least twice the annual interest requirements
on all Class A Bonds to be outstanding (Bond Ratio). For the
year ended December 31, 19931995 the Bond Ratio was 3.70.3.97. The
issuance of additional Class A Bonds also is restricted also to an
additional principal amount equal to (i) 60% of unfunded net
property additions (which unfunded net property additions totaled
approximately $219.9$162.3 million at December 31, 1993)1995), Class A Bonds issued on the
basis of(ii)
retirements of Class A Bonds (which retirement credits totaled
$10.9$64.8 million at December 31, 1993)1995), (iii) and Class A Bonds
issued on the basis of cash on deposit
with the Trustee.
22
The Company has placed a new bond indenture (New Mortgage) dated April 1,
1993 oncovering substantially all of its electric properties under
which its future mortgage-backed debt (New Bonds) will be issued.
New Bonds are expected to be issued under the New Mortgage on the basis of a
like principal amount of Class A Bonds issued under the Old
Mortgage which have been deposited with the Trustee of the
New Mortgage (of which $157$185 million were available for such
purpose as of December 31, 1993)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 12twelve consecutive months out of the 18eighteen 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, 19931995 the New Bond
Ratio was 5.0.5.31.
The following financing transaction has occurred since
December 31, 1994:
On April 29, 199312, 1995 the Securities and Exchange Commission
declared effective a registration statement for the issuance of
up to $700Company issued $100 million of
New Bonds. The following series,
aggregating $600 million, have been issued under such
registration statement:
On June 9, 1993, $100 million,First Mortgage Bonds, 7 5/8% Seriesseries due JuneApril 1, 20232025
to repay short-term borrowings in a like amount.
On July 1, 1993, $100 million, 6% Series due June 15, 2000,
and $150 million, 7 1/8% Series due June 15, 2013, and on
July 20, 1993, $150 million, 7 1/2% Series due June 15,
2023, to redeem, on July 20, 1993, $382,035,000 of First and
Refunding Mortgage Bonds maturing between 1999 and 2017
and bearing interest at rates between 8% and 9 7/8% per
annum.
On December 20, 1993, $100 million, 6 1/4% Series due
December 15, 2003 to repay short-term borrowings in a like
amount.
On June 1, 1993 the Company redeemed the following amounts
of First and Refunding Mortgage Bonds: $35 million, 10 1/8%
Series due 2009 and $13 million, 9 7/8% Series due 2009.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 12twelve months or less, but not later than
December 31, 1995.1997.
The Company has $127.0had $165 million authorized and unused lines of
credit at December 31, 1993.1995. In addition, the Company has a
credit agreement for a maximum of $75$125 million to finance nuclear
and fossil fuel inventories, with $38.2 millionthe full
amount available at December 31, 1993.1995. 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 12twelve consecutive months immediately preceding
the month of issuance isare 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, 19931995 the Preferred Stock Ratio was 2.52.2.58.
The Company anticipates that its 19941996 cash requirements of
$417.4$378.9 million will be met primarily through internally generated funds
(approximately 32% excluding77%, after payment of dividends), the sales of
additional equity securities, additional equity contributions
from SCANA and the incurrence of additional short-term and long-termlong-
term indebtedness. The timing and amount of such financing will
depend upon market conditions and other factors. Actual 19941996
expenditures may vary from the estimates set forth above due to
factors such as inflation and economic conditions, regulation and
legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.
The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements.
23
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 hashad a compliance date of January 1,
1995 and the second, January 1, 2000. The Company meets allCompany's facilities
did not require modifications to meet the requirements of Phase
I and therefore will not have to implement
changes until compliance with Phase II requirements is necessary.I. The Company then will most likely meet its compliancethe Phase II requirements
through the burning of natural gas and/or lower sulfur coal the addition of scrubbers to coal-firedin
its generating units and the purchase and use of sulfur dioxide
emission allowances. Low nitrogen oxide burners will beare being
installed to reduce nitrogen oxide emissions.
Theemissions 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 is continuinghad filed compliance plans
related to refine a detailed compliance
plan that must be filedPhase II requirements with the EPA by January 1, 1996.DHEC. The Company
currently estimates that excluding GENCO, air emissions control equipment will
require capital expenditures of $190$113 million over the 1994-19981996-2000
period to retrofit existing facilities, and anwith increased operation
and maintenance cost of $22approximately $1 million per year. Total capital expenditures required toTo
meet compliance requirements through the year 2003 are anticipated2005, 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 be
approximately $211 million.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 requires promulgation ofdirected DHEC to promulgate regulations addressing specified
subjects, one of which affectsfor the managementdisposal of
industrial solid waste. ThisDHEC has promulgated a proposed
regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation,which, if adopted as a final regulation in its present
form, couldwould significantly impactincrease the Company's engineering, designand GENCO's
costs of construction and operation of existing and future ash
management facilities.
Potential cost impacts could be substantial.
As described in Note 1L of Notes to Consolidated Financial
Statements, the25
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 isestimates are made of the amount of expenditures,cost, 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 differ from the original estimates.
Amounts estimated and accrued to date ($19.6 million) for site assessments and
cleanup ofrelate primarily to regulated operations have beenoperations; such amounts
are deferred and are being amortized and recovered through rates
over a tenten-year period for electric operations and an eight-
year period.period for gas operations. Deferred amounts totaled
$18.0 million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates to date include, among other things,items, the costs
estimated to be
associated with the matters discussed in the following
paragraphs.
The Company and SCANA each own twoowns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company and SCANA have each maintainedmaintains an active review of their respectivethe 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 18eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority List, but may
be added before cleanup is initiated. The potentially
responsible parties (PRP)PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-
cleanuppre-cleanup site investigationsinvestigation process to be
compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a
Remedial Investigation/Feasibility Study (RI/FS) and a corresponding
Scope of Work. Actual fieldField work began in November 1, 1993 after
final approval and authorization was granted by EPA.1993. The Company
is also working with the City of Charleston to investigate
potential contamination from the manufactured gas plant atwhich may
have migrated to the city'sCity's aquarium site. During 1993In 1994 the City of
Charleston notified the Company settled its obligations atthat it considers the Yellow
Water Road Superfund Site near Jacksonville, Florida,Company to
be responsible for a $43.5 million increase in costs of the
Spencer
Transformer and Equipment Site in West Virginia and Elliott's
Auto Parts in Benton, Arkansas. No further expenses are
anticipated for these sites.aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes it has been listed asmeritorious defenses against this claim and does
not expect its resolution to have a PRP and has recorded
liabilities, which are not considered material for the Macon-
Dockery waste disposal site near Rockingham, North Carolina, the
Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a
landfill owned by Lexington County in South Carolina.
24
Litigation
In January 1994 the Company, actingimpact on behalfits
financial position or results of itself and
the PSA (as co-owners of Summer Station), reached a settlement
with Westinghouse Electric Corporation (Westinghouse) resolving a
dispute involving steam generators provided by Westinghouse to
Summer Station which are defective in design, workmanship and
materials. Terms of the settlement are confidential by agreement
of the parties and order of the court.operations.
Regulatory Matters
The Company had filed an
actionfor electric rate relief in May 1990 against Westinghouse in1995 to
encompass primarily the U. S. District
Court for South Carolina; an order dismissing this suit
was issued on January 12, 1994.
Regulatory Matters
On June 7, 1993remaining costs of completing the Cope
Generating Station. As discussed under "Liquidity and Capital
Resources," the PSC issued an order on theJanuary 9, 1996 increasing
electric retail rates.
The Company's pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually on a
test year basis. These rates are to be implemented in two
phases over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, on a test year basis.
The Company'sregulated 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 allowing for the potential requirement
that a utilityby 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.
Other
In November 1992climates 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. 112 "Employers' Accounting121, "Accounting for Postemployment Benefits.the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." The provisions of the Statement, which is effectivewill be
implemented by the Company for calendarthe fiscal year 1994, establishes certain conditions forbeginning January
1, 1996, require the recognition of costs of benefits to former employees after
employment but before retirement. The Statement requires
recognition ofa loss in the obligation to provide postemployment benefits
if such obligation is attributable to services previously
rendered,income
statement and related disclosures whenever events or changes in
circumstances indicate that the obligation relates to rights which vest, payment of
the benefits is probable and thecarrying amount of such benefits cana long-lived
asset may not be reasonably estimated.recoverable. The Company does not anticipatebelieve that
applicationadoption of thisthe provisions of the Statement will have a significantmaterial
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
OverviewNet Income
Net income and the percent increase (decrease) from the
previous year for the years 1993, 19921995, 1994 and 19911993 were as follows:
1995 1994 1993 1992 1991
Net income $169,185 $152,043 $145,968 $102,163 $122,836
Percent increase (decrease) in net
income 11.27% 4.16% 42.9%
(16.8%) 1.7%
19931995 Net income increased for 1993the 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 other operating expenses.
1992 Net income for 1992 decreased from 1991 primarily
due to the recording of an $11.1 million (after
interest and income taxes) reserve against earnings related
to the August 31, 1992 retail electric rate ruling from the
South Carolina Supreme Court (see Note 2E of Notes to
Consolidated Financial Statements) and as a result of
increased non-fuel operating expenses and interest charges.
The Company's financial statements include AFC.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. Both anAn equity portion of AFC is included in
nonoperating income and a debt portion of AFC areis included in
nonoperating incomeinterest charges (credits) as noncash items, both which have the
effect of increasing reported net income. AFC represented
approximately 5.6%7.9 % of income before income taxes in 1993, 5.5%1995, 6.3%
in 19921994 and 3.7%5.6% in 1991.
251993.
27
Electric Operations
Electric sales margins for 1993, 19921995, 1994 and 19911993 were as
follows:
1995 1994 1993 1992 1991
(Millions of Dollars)
Electric revenues $1,006.6 $974.3 $940.2
$844.5 $867.7
Provision(Provision) for rate refunds .3 (14.6) - 1.2 0.3
Net Electric operating revenues 1,006.6 975.5 940.5 829.9 867.7
Less: Fuel used in electric generation 177.6 176.6 164.2 161.7 160.6
Purchased power 98.2 112.9 111.1
80.4 102.1
Margin $ 730.8 $686.0 $665.2
$587.8 $605.0
19931995 The increase in electric sales margin from 1992 to
1993 isincreased over the prior
year primarily as a result of increased residential and
commercial KWH sales due tothe combined impact of
warmer weather and customer growth, an
increase in retail electric rates beginning in June 1993,
and a $14.6 million reserve recorded in 1992 as discussed
below.
1992 The 1992 electric sales margin decreased from
1991 primarily due to the recording of a $14.6 million
reserve, before interest and income taxes, related to the
August 31, 1992 ruling from the Supreme Court (see Note 2E
of Notes to Consolidated Financial Statements) and a $1.9
million billing-related litigation settlement included in
1991 electric operating revenues.
Increases (decreases) in megawatt hour (MWH) sales volume by
classes are presented in the following table:
Increase (Decrease)
From Prior Year
Volume (MWH)
Classification 1993 1992
Residential 494,874 2,380
Commercial 305,560 37,749
Industrial 203,178 49,248
Sale for Resale (excluding interchange) 59,611 12,945
Other 24,873 (3,116)
Total territorial 1,088,096 99,206
Interchange 121,013 16,558
Total 1,209,109 115,764
Warmerthird quarter of 1995, colder
weather and an increase in the numberfourth 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
3,5573,683 MW (including Williams Station) on July 29, 1993. The
previous year's record of 3,380 MW was set on July 13, 1992.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 1993, 19921995, 1994 and 19911993 were as follows:
1995 1994 1993 1992 1991
(Millions of Dollars)
Gas operating revenues $200.6 $201.7 $174.0 $160.8 $150.8
Less: Gas purchased for resale 125.0 127.8 107.7 95.8 93.2
Margin $ 75.6 $ 73.9 $ 66.3
$ 65.0 $ 57.6
19931995 The 1993 gas sales margin increased from 1992over the prior year
primarily as a result of increases in higher margin
residential and regular commercialinterruptible gas
sales.
19921994 The 1992 gas sales margin increased from 1991over the prior year
primarily due to recoveriesas a result of $4.2 million allowed under a
weather normalization adjustment, increases in residential
usage due to unseasonably cool weather during May 1992, and
increased transportation volumes.
26interruptible
gas sales.
28
Increases (decreases) from the prior year in dekatherm (DT)
sales volume by classes, are presented in the following table:
Increase (Decrease)
From Prior Year
Volume (DT)including transportation gas, were as
follows:
Classification 1993 19921995 1994
Residential 723,356 1,303,673802,211 (477,886)
Commercial (186,529) 22,188623,533 970,726
Industrial 547,193 (424,657)2,528,974 5,057,404
Transportation gas (1,866,414) (1,524,089)
Total 1,084,020 901,2042,088,304 4,026,155
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including
taxes, are presented in the following table:
Increase (Decrease)
From Prior Yearwere as follows:
Classification 1993 19921995 1994
(Millions of Dollars)
Other operation and maintenance $(7.8) $ 8.1 $11.53.9
Depreciation and amortization 4.2 5.410.6 5.7
Income taxes 29.9 (17.2)12.9 2.8
Other taxes (.2) 4.75.1 5.0
Total $42.0 $ 4.4
1993$20.8 $17.4
1995 Other operation and maintenance expenses increased for
1993decreased
primarily due to the implementationas a result of Financial
Accounting Standards Board Statement No. 106 (See Note 1J
of Notes to Consolidated Financial Statements) pursuant to
the June 1993 PSClower pension costs and lower costs
at electric rate order and the amortization
of environmental expenses. The depreciation and
amortization increase reflects additions to plant in
service. The increase in income taxes corresponds to the
increase in the corporate tax rate from 34% to 35%
retroactive to January 1, 1993.
1992 Other operation and maintenance expenses increased for
1992 primarily due to increases in administrative and
general expense, increase in nuclear regulatory fees, and
nuclear and transmission system maintenance.generating stations. The increase in
depreciation and amortization expense reflectsprimarily is
attributable to additions to plant in service.plant-in-service and the
expensing of software costs. The decreaseincrease in income tax
expense is primarily relatedcorresponds to the tax impact of the rate
refund (see Note 2E of Notes to Consolidated Financial
Statements) and to other decreasesincrease in operating income. The
increase in other taxes isreflects 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 higher
property taxes caused byan 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 increased
millage rates. In addition to the above, other taxes
increased due to increases in state license fees.depreciation rates. The increase in
other taxes reflects an increase in property taxes of
approximately $5 million.
Interest Expense
1993Increases (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, decreased approximately $1.8 millionis due primarily due to the redemptionissuance of
Firstadditional debt including commercial paper during the latter
part of 1994 and Refunding Mortgage Bonds andearly 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 at lower interest
ratesin July and the 1992 interest on the provision for rate
refund which were partially offset by interest on an
adjustment for the 1987-1988 income tax audit.
1992 Interest expense increased approximately $5.7$30 million
of Pollution Control Facilities Revenue Bonds in 1992 comparedNovember,
both to 1991 duefinance utility construction, and to the issuancesissuance of
the $145 million and $155 million of First and
Refunding Mortgage Bonds on July 24, 1991 and Augustlong-term debt during 1993.
29
1991, respectively, which more than offset the decreases
in interest expense resulting from the repayment of debt
and lower interest rates on remaining debt and interest of
$3.1 million accrued on the provision for rate refund (see
Note 2E of Notes to Consolidated Financial Statements).
27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditor'sAuditors' Report....................................... 2931
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 19931995 and 1992... 301994... 32
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1993, 19921995, 1994 and 1991............. 321993............. 34
Consolidated Statements of Cash Flows for the years ended
December 31, 1993, 19921995, 1994 and 1991............................. 331993............................. 35
Consolidated Statements of Capitalization as of
December 31, 19931995 and 1992................................... 341994................................... 36
Notes to Consolidated Financial Statements..................... 36
Supplemental Financial Statement Schedules:
Schedule V - Property, Plant and Equipment for the
years ended December 31, 1993, 1992 and 1991................. 54
Schedule VI - Accumulated Depreciation and Amortization
of Property, Plant and Equipment for the years
ended December 31, 1993, 1992 and 1991....................... 5738
Supplemental financial statement schedules other than those listed above are omitted because of the
absence of conditions under which they are required or because the required
information is included in the consolidated financial statements or in the
notes thereto.
2830
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, 19931995 and 19921994 and the
related Consolidated Statements of Income and Retained Earnings
and of Cash Flows for each of the three years in the period ended
December 31, 1993. Our audits also included the financial
statement schedules listed in the index on page 28.1995. These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements and
financial statement schedules based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company at December 31, 19931995 and 19921994 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 19931995 in conformity with generally
accepted accounting principles.
Also, in our opinion, such
financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in
all material respects the information set forth therein.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 1994
291996
31
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1993 19921995 1994
(Thousands of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $3,067,881 $2,954,064$3,277,530 $3,165,391
Gas 272,506 263,675320,847 307,929
Transit 3,769 3,2873,768 3,785
Common 72,804 65,12491,616 77,327
Total 3,416,960 3,286,1503,693,761 3,554,432
Less accumulated depreciation and amortization 1,097,531 1,039,9391,196,279 1,171,758
Total 2,319,429 2,246,2112,497,482 2,382,674
Construction work in progress 338,677 217,074613,683 571,867
Nuclear fuel, net of accumulated amortization 29,087 39,91646,492 43,591
Utility Plant, Net 2,687,193 2,503,2013,157,657 2,998,132
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 12,709 12,60411,603 11,931
Current Assets:
Cash and temporary cash investments (Note 8) 193 24,3026,798 346
Receivables - customer and other 119,296 91,279154,816 127,679
Receivables - affiliated companies (Note 1) 244 3417,132 18,121
Inventories (at(At average cost):
Fuel (Notes 1, 3 and 4) 31,192 32,69735,812 31,310
Materials and supplies 43,372 43,26843,583 43,228
Prepayments 10,089 12,189
Accumulated Deferred Income Taxes 9,015 -
Total Current Assets 213,401 204,076
Deferred Debits:
Unamortized debt expense 11,060 8,35410,158 14,389
Accumulated deferred income taxes (Notes 1 and 7) - 36,75719,420 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) 14,860 19,1066,369 10,614
Nuclear plant decommissioning fund (Note 1) 25,103 20,84136,070 30,383
Other (Note 1) 225,613 86,014273,056 251,928
Total Deferred Debits 276,636 171,072355,454 324,024
Total $3,189,939 $2,890,953
See Notes to Consolidated Financial Statements.
30$3,802,433 $3,587,091
32
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1993 19921995 1994
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' InvestmentInvestment:
Common equity (Note 5):
Common equity $1,051,334 $ 963,741 $1,315,072 $1,133,432
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,077,361 989,7681,341,099 1,159,459
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 52,840 56,15446,243 49,528
Long-Term Debt, Net (Notes 3, 4 and 8) 1,097,043 944,416
Advances from Affiliated Companies, Net (Note 3) - 1,5481,279,379 1,231,191
Total Capitalization 2,227,244 1,991,8862,666,721 2,440,178
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 1,011 3380,500 100,000
Notes payable - affiliated companies - 19,409
Current portion of long-term debt (Note 3) 13,719 12,75436,033 33,042
Current portion of preferred stock (Note 6) 2,504 2,4852,439 2,418
Accounts payable 68,182 49,74971,731 61,466
Accounts payable - affiliated companies (Note(Notes 1 and 3) 28,630 32,222
Estimated rate refunds and related interest (Note 2) 2,509 17,81126,212 33,357
Customer deposits 12,207 12,91812,518 12,668
Taxes accrued 39,965 51,12764,008 46,646
Interest accrued 17,764 26,43321,626 21,534
Dividends declared 29,982 28,35333,126 28,489
Other 10,042 6,18512,507 15,525
Total Current Liabilities 226,515 240,070360,700 374,554
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 480,808 451,046488,310 503,723
Accumulated deferred investment tax credits (Notes 1 and 7) 84,447 87,69278,316 81,546
Accumulated reserve for nuclear plant decommissioning (Note 1) 25,103 20,84136,070 30,383
Other (Note 1) 145,822 99,418172,316 156,707
Total Deferred Credits 736,180 658,997775,012 772,359
Commitments and Contingencies (Note 10) - -
Total $3,189,939 $2,890,953$3,802,433 $3,587,091
See Notes to Consolidated Financial Statements.
3133
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1995 1994 1993 1992 1991
(Thousands of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $1,006,566 $ 975,526 $ 940,547
$ 829,938 $ 867,685
Gas 200,632 201,746 174,035
160,820 150,788
Transit 3,889 4,002 3,851 3,623 3,869
Total Operating Revenues 1,211,087 1,181,274 1,118,433 994,381 1,022,342
Operating Expenses:
Fuel used in electric generation 177,579 176,581 164,187 161,691 160,640
Purchased power (including affiliated
purchases)(Note 1) 98,231 112,900 111,111 80,431 102,116
Gas purchased from affiliate for resale (Note 1) 125,032 127,846 107,722 95,854 93,179
Other operation 211,318 214,344 207,126
199,819 190,824
Maintenance 53,071 57,801 61,107 60,279 57,777
Depreciation and amortization (Note 1) 117,584 106,952 101,220 97,064 91,618
Income taxes (Notes 1 and 7) 96,956 84,066 81,280 51,382 68,543
Other taxes (Note 12) 75,462 70,366 65,361 65,594 60,939
Total Operating Expenses 955,233 950,856 899,114 812,114 825,636
Operating Income 255,854 230,418 219,319 182,267 196,706
Other Income (Note 1):
Allowance for equity funds used during construction 9,499 7,989 7,496 4,577 2,966
Other income (loss), net of income taxes 54 (718) (911) (1,571) 317
Total Other Income (Loss)9,553 7,271 6,585 3,006 3,283
Income Before Interest Charges 265,407 237,689 225,904 185,273 199,989
Interest Charges (Credits):
Interest on long-term debt, net 98,361 87,361 79,410 80,217 74,250
Other interest expense (Note(Notes 1 and 3) 9,324 5,189 5,812 6,777 7,090
Allowance for borrowed funds used
during construction (Note 1) (11,463) (6,904) (5,286) (3,884) (4,187)
Total Interest Charges, Net 96,222 85,646 79,936 83,110 77,153
Net Income 169,185 152,043 145,968 102,163 122,836
Preferred Stock Cash Dividends (At stated rates) (5,687) (5,955) (6,217) (6,474) (6,706)
Earnings Available for Common Stock 163,498 146,088 139,751 95,689 116,130
Retained Earnings at Beginning of Year 324,101 291,713 262,262 265,864 246,734
Common Stock Cash Dividends Declared (Note 5) (121,363) (113,700) (110,300) (99,291) (97,000)
Retained Earnings at End of Year $ 291,713366,236 $ 262,262324,101 $ 265,864291,713
See Notes to Consolidated Financial Statements.
3234
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995 1994 1993 1992 1991
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $169,185 $152,043 $145,968 $102,163 $122,836
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 117,839 107,103 101,370 97,212 91,805
Amortization of nuclear fuel 20,017 13,487 18,156 23,190 18,384
Deferred income taxes, net (17,632) 13,133 56,982 (15,959) 29,680
Deferred investment tax credits, net (3,230) (2,901) (3,245) (3,245) (3,244)
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) (8,461) (7,153)
Unamortized loss on reacquired debt (3,325) (129) (17,094) (112) 139
Early retirements (24,823) (7,086) (11,840) - -
Nuclear refueling accrual 6,957 (4,881) (6,086) 11,862 (6,192)
Over (under) collections, fuel adjustment clause 18,986 (17,965) (13,728)
7,901 (1,236)Emission allowances (9,105) (19,409) -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (16,148) (26,260) (27,920) 4,319 (4,210)
(Increase) decrease in inventories (4,857) 26 1,401 1,069 8,647
Increase (decrease) in accounts payable 3,120 (430) 16,757 2,526 (28,561)
Increase (decrease) in estimated rate
refunds and related interest - (2,509) (15,302) 17,811 -
Increase (decrease) in taxes accrued 17,362 6,681 (11,162) 36 7,150
Increase (decrease) in interest accrued 92 3,770 (8,669) 83 9,893
Other, net 886 (2,457) 6,071(14,623) 14,106 8,002
Net Cash Provided From Operating Activities 173,294 237,938 244,009252,413 211,901 180,410
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, (300,620) (243,329) (215,303)net of AFC (271,804) (406,054) (287,838)
Nonutility property and investments (111) (287) (248)
(205) (447)
Principal noncash item:
Allowance for funds used during construction 12,782 8,461 7,153Transfer of assets from SCANA - 6,285 -
Net Cash Used For Investing Activities (271,915) (400,056) (288,086) (235,073) (208,597)
Cash Flows From Financing Activities:
Proceeds:
Issuance of notes payable - affiliated company - 19,409 -
Issuance of mortgage bonds 600,00099,583 99,207 592,884
Issuance of pollution control bonds - 300,00030,000 -
Equity contributions from parent 139,505 43,426 58,142
126,838Other long-term debt 2,543 11,200 2,562
Repayments:
Notes payable - Other Long-term debt 2,562affiliated company (19,409) - -
Repayments:
Mortgage bonds (64,779) - (430,000)
(35,890) (8,000)
Other Long-termlong-term debt (12,548) (1,662) (405) (120) (75,285)
Preferred stock (3,264) (3,398) (3,295) (3,199) (2,622)
Dividend Payments:
Common stock (116,663) (115,100) (108,641) (96,550) (73,000)
Preferred stock (5,750) (6,048) (6,247) (6,558) (6,718)
Short-term borrowings, net (19,500) 98,989 978
(20) (130,417)
Fuel and emission allowance financings, net 26,236 13,844 (18,948) (6,628) (4,292)
Advances - affiliated companies, net - (1,559) (3,463) (2,899) (3,430)
Net Cash Provided From (Used For) Financing Activities 90,683 (25,026) (3,764)25,954 188,308 83,567
Net Increase (Decrease) in Cash and Temporary Cash Investments 6,452 153 (24,109) (22,161) 31,648
Cash and Temporary Cash Investments, January 1 346 193 24,302 46,463 14,815
Cash and Temporary Cash Investments, December 31 $ 1936,798 $ 24,302346 $ 46,463193
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 $ 86,093 $ 70,201
- Income taxes 95,827 77,295 79,612 72,584 38,313
Noncash Financing Activities:
Capital lease obligations recorded - - 2,864
Department of Energy Decontaminationdecontamination and Decommissioning Fund 4,965decommissioning
fund obligation - - See Notes to Consolidated Financial Statements.
334,965
See Notes to Consolidated Financial Statements.
35
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1993 19921995 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 188,713 130,624377,822 238,369
Capital stock expense (debit) (5,497) (5,550)(5,391) (5,443)
Retained earnings 291,713 262,262366,236 324,101
Total Common Equity 1,051,3341,315,072 49% 1,133,432 47% 963,741 48%
Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5):
$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1993 19921995 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 1993 19921995 1994 Current Through Minimum
7.70% 92,992 96,00086,965 89,984 101.00 - 101.00 9,299 9,6008,696 8,998
8.12% 131,899 136,265123,045 126,835 102.03 - 102.03 13,190 13,62612,305 12,684
Total 224,891 232,265210,010 216,819
$50 Par Value - Authorized - 1,639,8861,614,405 shares
Shares Outstanding Redemption Price
Eventual
Series 1993 19921995 1994 Current Through Minimum
4.50% 20,800 22,40017,519 19,088 51.00 - 51.00 1,040 1,120876 954
4.60% 3,834 5,334834 2,334 50.50 - 50.50 192 26742 117
4.60%(A) 30,052 32,05226,052 28,052 51.00 - 51.00 1,503 1,6021,303 1,403
4.60%(B) 81,600 85,00074,800 78,200 50.50 - 50.50 4,080 4,2503,740 3,910
5.125% 74,000 75,00072,000 73,000 51.00 - 51.00 3,700 3,7503,600 3,650
6.00% 89,600 92,80083,200 86,400 50.50 - 50.50 4,480 4,6404,160 4,320
8.72% 160,000 192,00095,985 127,956 51.00 12-31-98 50.00 8,000 9,6004,799 6,398
9.40% 197,191 203,678183,219 190,245 51.175 - 51.175 9,860 10,1849,161 9,512
Total 657,077 708,264553,609 605,275
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 19931995 and 19921994
Total PrPreferred Stock (Subject to purchase or sinking funds) 48,682 51,946
Less: Current portion, including sinking fund requirements 2,504 2,4852,439 2,418
Total Preferred Stock, Net (Subject to purchase or sinking funds) 52,840 3% 56,154 3%
See Notes to Consolidated Financial Statements.
3446,243 2% 49,528 2%
36
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1993 19921995 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- 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
8% 1999 - 35,000
9 1/8% 1999 - 15,000
8% 2001 - 35,000
7 1/4% 2002 30,000 30,000
9% 2006 130,771 145,000 145,000
9 1/8% 2006 - 50,000
8.40% 2006 - 50,000
8 3/8% 2007 - 30,000
8.90% 2008 - 30,000
10 1/8% 2009 - 35,000
9 7/8% 2009 - 50,000
8 3/4% 2017 - 100,000
8 7/8% 2021 155,000120,450 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,760 6,8556,560 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
Capitalized Lease Obligations,Orangeburg County Series 1994 due 1991-1997 (various rates between
5 3/4% and 10%) 2,897 4,875
Installment Note Payable, due 1996 2,277 -2024 (daily adjusted rate) 30,000 30,000
Department of Energy Decontamination and Decommissioning Obligation 4,634 -
Nuclear and Fossil Fuel Liability 36,750 55,6983,560 3,922
Commercial Paper 76,830 61,794
Other 3,993 3,294
Total 1,116,803 960,913Long-Term Debt 1,319,649 1,269,155
Less: Current maturities, including sinking fund requirements 13,719 12,75436,033 33,042
Unamortized discount 6,041 3,7434,237 4,922
Total Long-Term Debt, Net 1,097,043 49% 944,4161,279,379 48% Advances from Affiliated Companies 1,559 5,023
Less: Current Portion of Advances - Affiliated Companies 1,559 3,475
Advances from Affiliated Companies, Net - - 1,548 -1,231,191 50%
Total Capitalization $2,227,244$2,666,721 100% $1,991,886$2,440,178 100%
See Notes to Consolidated Financial Statements.
37
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
The Company, a public utility, is a South Carolina
corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation (SCANA), a South Carolina holding company. The
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. (See Note 1M).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 South Carolina Pipeline Corporation (Pipeline Corporation) and
at December 31, 19931995 and 19921994 the Company had approximately $15.1$17.5
million and $15.2$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
South Carolina
Generating Company, Inc. (GENCO),GENCO, under a unit power sales agreement. At December 31, 19931995
and 19921994 the Company had approximately $7.5$8.2 million and $4.5$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 $73.1 millionin 1995, 1994 and $92.3 million in
1993, 1992 and 1991, respectively.
Total interest income, (basedbased on market interest rates)rates,
associated with the Company's advances to affiliated companies
was approximately $129,000, $231,000$174,000, $5,000 and $141,000$143,000 in 1995, 1994 and
1993, 1992
and 1991.respectively.
Included in "Other interest expense" for 1993, 19921995, 1994 and 19911993
is approximately $29,000, $16,000$114,000, $279,000 and $830,000,$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
Federal Energy Regulatory Commission (FERC)FERC and as adopted by The
Public Service Commission of South Carolina (PSC).
C.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 V. C. Summer Nuclear Station (Summer Station), and The South Carolina Public Service Authority
(PSA)PSA are
joint owners of the 885 MW Summer Station in the proportions of two-thirds
and one-third, respectively. The parties share the operating
costs and energy output of the plant in these proportions. Each
party, however, provides its own financing. Plant in servicePlant-in-service
related to the Company's portion of Summer Station was
approximately $920.2$925.1 million and $916.0$923.1 million as of December
31, 19931995 and 1992,1994, respectively. Accumulated depreciation
associated with the Company's share of Summer Station was
approximately $285.3$261.0 million and $262.2$297.9 million as of December
31, 19931995 and 1992,1994, 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.
36
D.E. Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC),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, of
the costs of debt and equity capital dedicated to construction
investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates
for utility services. The Company has calculated AFC using
composite rates of 9.4%8.6%, 8.5% and 9.4% for 1995, 1994 and 9.8% for 1993, 1992 and 1991,
respectively. These rates do not exceed the maximum allowable
rate as calculated under FERC Order No. 561. Interest on nuclear
fuel in process and sulfur dioxide emission allowances is
capitalized at the actual interest amount.
E.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 1993, 19921995, 1994 and 1991.
F.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 costcosts 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. At December 31, 1993 and
1992 theThe Company had
overcollected through the electric fuel clausecost component
approximately $9.2$3.8 million at December 31, 1995 and
$17.7undercollected approximately $3.5 million respectively,at December 31, 1994
which are included in "Deferred Credits - Other.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, 19931995 and 19921994 the Company had
undercollected through the gas cost recovery procedure
approximately $11.0$4.6 million and $5.7$16.3 million, respectively, which
are included in "Deferred Debits - Other."
G.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 2.97%3.02%, 3.00%3.01%,
and 2.97% for 1993, 19921995, 1994 and 1991,1993, 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 Department of EnergyDOE under a contract for disposal of spent nuclear fuel.
37
H.I. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
TheBased on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
currently estimated, (inin 2022 dollars assuming ana 4.5% annual 4.5% rate of
inflation)inflation, to be
approximately $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 CompanyCompany's method of funding decommissioning cost
is referred to as COMReP (Cost of Money Reduction Plan). Under
this plan, funds collected through rates $2.5 million and $1.6($3.2 million in 1993each of
1995 and 1992, respectively. The amounts1994) 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 deposited
intransferred by the Company
to an external trust fund in compliance with the financial
assurance requirements of the NRC.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 addition, pursuantresponse 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 National Energy Policy ActNEPA passed by Congress in 1992, the Company
has recorded a liability for its estimated share of amounts
required by the U. S.
Department of EnergyDOE for its decommissioning fund. SCE&G will
recover the costs associated with thisThe liability,
totaling $4.6approximately $3.6 million at December 31, 1993,1995, 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, these amounts havethis amount has been
deferred and areis included in "Deferred Debits-Other" and "Long-Term Debt, Net.Debits - Other."
I.J. Income Taxes
The Company is included in the consolidated Federal and
State income
tax returnsreturn filed by SCANA. Income taxes are allocated to the
Company based on its contribution to the consolidated taxable income.
The Company adoptedtotal.
As required by Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," effective
January 1, 1993. Prior years' financial statements have not been
restated. Deferred tax assets and liabilities were adjusted from
the amounts recorded at December 31, 1992 under prior standards
to the amounts required at January 1, 1993 under Statement No.
109 at currently enacted income tax rates. The adjustments were
charged or credited to regulatory assets or liabilities if the
Company expects to recover the resulting additional income tax
expense from, or pass through the resulting reductions in income
tax expense to, customers of the Company; otherwise they were
charged or credited to income tax expense. The cumulative effect
of adopting Statement No. 109 on retained earnings as of January
1, 1993, as well as the effect of adoption on net income for the
year ended December 31, 1993, was not material. The combined
effect of adopting Statement No. 109 and adjusting deferred tax
assets and liabilities for the change in 1993 of the corporate
Federal income tax rate from 34% to 35% resulted in balances of
$97.0 million in regulatory assets (included in "Deferred Debits-
Other") and $56.6 million in regulatory liabilities (included in
"Deferred Credits-Other").
In accordance with Statement
No. 109, deferred tax assets and liabilities are recorded for the
tax effecteffects 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.
Prior to the adoption of Statement No. 109 on January 1,
1993, the Company recorded a deferred income tax provision on all
material timing differences between the inclusion of items in
pretax financial income and taxable income each year, except for
those which were expected to be passed through to, or collected
from, customers. Accumulated deferred income taxes were
generally not adjusted for changes in enacted tax rates.
J.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.
38
Net periodic pension cost as determined by an
independent actuary, for the years ended December 31,
1993, 19921995, 1994 and 19911993 included the following components:
1993 1992 1991
(Thousands of Dollars)
Service cost-benefits1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 5,187 $ 8,684 $ 7,629 $ 7,174 $ 6,367
Interest cost on projected benefit obligation 20,413 19,628 18,334
Adjustments: Return on plan assets (50,389) (28,607) (51,440)
Net amortization and deferral 25,936 8,096 36,263
Amounts contributed by the Company's affiliates (175) (154) (1,177)
Net periodic pension cost of the Company $ 3,414 $ 6,137 $ 8,347
The following table sets forth the funded status of the plan, as determined
by an independent actuary, at December 31, 1993 and 1992:
1993 1992
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $204,794 $177,930
Nonvested benefit obligation 14,085 17,110
Accumulated benefit obligation $218,879 $195,040
Projected benefit obligation $295,718 $258,440
Plan assets at fair value
(invested primarily in
equity and debt securities) 351,648 304,114
Plan assets greater than
projected benefit obligation 55,930 45,674
Unrecognized net transition liability 10,713 11,555
Unrecognized prior service costs 9,294 10,563
Unrecognized net gain (64,607) (63,633)
Pension asset recognized
in SCANA's Consolidated Balance Sheets $ 11,330 $ 4,159
The accumulated benefit obligation is based on the plan's benefit formulas without considering expected
future salary increases. The following table sets forth the assumptions used in the amounts shown above for the
years 1993, 1992 and 1991.
1992 and
1993 1991
Annual discount rate used to determine benefit obligations 7.25% 8.0%
Expected long-term rate of return on plan assets 7.25% 8.0%
Discount rate used in determining pension cost 8.0% 8.0%
Assumed annual rate of future salary increases for projected benefit obligation 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 7.25%7.5% and the change in the
expected salary increase rate from 2.5% to 3.0% as of December
31, 19931995 increased the projected benefit obligation and reduceddecreased
the unrecognized net gain by approximately $4.1$28.6 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. On January 1, 1993 the Company adopted
Statement No. 106 "Employers' Accounting for Postretirement
Benefits Other Than Pensions." This Statement requires that the
costThe costs of postretirement benefits
other than pensions beare accrued during the years the employees
render the service necessary to be eligible for the applicable
benefits. ThePrior to 1993, the Company previously expensed these benefits,
which are primarily health care, as claims were incurred. The accumulated obligation for these
benefits at January 1, 1993 was approximately $68 million
(transition liability) and the annualized increase in expenses
(net of payments to current retirees), including the amortization
of the transition liability over approximately 20 years as
provided for by the Statement, is approximately $4.7 million. In its
June 1993 electric rate order, (see Note 2A) the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. Such expenses had been deferred
through May 31, 1993 pursuant to a December 10, 1992 accounting
directive allowing deferral pending consideration of recovery in
future rate proceedings. For the year ended December 31, 1993
theThe Company expensed approximately $4.3$8.5 million and
$8.6 million, net of payments to current retirees.
39
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 as determined by
an independent actuary for the yearyears ended
December 31, 1995, 1994 and 1993, included the following
components (thousandscomponents:
1995 1994 1993
(Thousands of dollars):
Service cost-benefits earned during the period $ 1,908
Interest cost on accumulated postretirement benefit
obligation 5,502
Adjustments: Return on plan assets -
Amortization of unrecognized transition
obligation 3,344
Other net amortization and deferral -
Amounts contributed by the Company's affiliates (525)
Net periodic postretirement benefit cost $ 10,229
The following table sets forth the unfunded status of the plan, as determined
by an independent actuary, at December 31, 1993 (thousands of dollars):
Accumulated postretirement benefit obligations for:
Retirees $ 40,865
Other fully eligible participants 25,767
Other active participants 6,841
Accumulated postretirement benefit obligation 73,473
Plan assets at fair value -
Plan assets less accumulated postretirement benefit
obligation (73,473)
Unrecognized net transition liability 64,925
Unrecognized prior service costs -
Unrecognized net (gain) loss 4,248
Postretirement benefit liability recognized
in Consolidated Balance Sheet $ (4,300)
The accumulated postretirement benefit obligation is based upon the plan's
benefit provisions and the following assumptions:
Assumed health care cost trend rate used to
measure expected 1994 costs 12.25%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.25%
Discount rate used in determining post-
retirement benefit costs 7.25%
Assumed annual rate of salary increases 4.75%
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-pointone 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, 19931995
and the accumulated postretirement benefit obligation as of
December 31, 19931995 would be to increase such amounts by $60,000$203,000
and $1.7$3.4 million, respectively.
K.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.
40
L.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
differ from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have beenare deferred and are being
amortized and recovered through rates over a ten-year period.period for
electric operations and an eight-year period for gas operations.
Such deferred amounts totaled $19.6$18.0 million and $18.3$20.2 million at
December 31, 19931995 and 1992,1994, respectively, and are included in
"Deferred Debits-Other.Debits - Other."
M.43
N. Fuel InventoryInventories
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.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 (seestatements. (See Note 4).
N. Postemployment Benefits
In November 1992 the Financial Accounting Standards Board
issued Statement No. 112 "Employers' Accounting for
Postemployment Benefits." The Statement, which is effective for
calendar year 1994, establishes certain conditions for the
recognition of costs of benefits to former employees after
employment but before retirement. The Statement requires
recognition of the obligation to provide postemployment benefits
if such obligation is attributable to services previously
rendered, the obligation relates to rights which vest, payment of
the benefits is probable, and the amount of such benefits can be
reasonably estimated. The Company does not anticipate that
application of this Statement will have a significant impact on
results of operations or financial position.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 19931995 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 June 7, 1993July 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 ongranting the Company's
pending electric rate proceeding allowingCompany an authorized return on
common equityincrease of
11.5%, resulting7.34% which will produce additional revenues of approximately
$67.5 million annually. The increase will be implemented in a 7.4% annualtwo
phases. The first phase, an increase in retail electric rates, or a projected $60.5revenues of
approximately $59.5 million annually based on a test year. These rates are toyear, or
6.47%, commenced on January 15, 1996. The second phase will be
implemented in two
phasesJanuary 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
two-year period: phase one, effective June 1993,
producing $42.0ten-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 annually,of depreciation reserves from
transmission and phase two, effective June
1994, producing $18.5 million annually, based on a test year.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 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 incomelow-income customers and denied the
Company's request to reduce the number of routes and frequency of
service. The new rates were placed into effect onin October 5, 1992.
The Company has appealed the PSC's order to the Circuit Court. During oral arguments in February 1994Court, which
on May 23, 1995, ordered the Circuit Court
retained jurisdiction and remanded the decisioncase back to the PSC for
reconsideration of several issues including the limited purposelow-income rider
program, routing changes, and the $.75 fare. The Supreme Court
declined to review an appeal of answering questions concerning the applicable regulatory principles usedCircuit Court decision and
dismissed the case. Another Petition for Reconsideration was
filed by the PSC in determining
these transit rates.
C. Since November 1, 1991 the Company's gas rate schedules
for its residential, small commercial and small industrial
customers have included a weather normalization adjustment. The
WNA minimizes fluctuations in gas revenues due to abnormal
weather conditions and has been approved through November 1994
subject to an annual reviewother intervenors, which was denied by the
PSC. The PSC order was based
on a return on common equity of 12.25%. The PSC also approved
the WNA for SCANA's directly owned natural gas distribution
system which is operated by the Company. The WNA became effective
the first billing cycleCircuit Court. Procedural matters in December 1991.
41
D. In May 1989 the PSC approved a volumetric and direct
billing method for Pipeline Corporation to recover take-or-pay
costs incurred from its interstate pipeline suppliers pursuant
to FERC-approved final and non-appealable settlements. In
December 1992 the Supreme Court approved Pipeline Corporation's
full recovery of the take-or-pay charges imposed by its suppliers
and treatment of these charges as a cost of gas. However, the
Supreme Court declared the PSC-approved "purchase deficiency"
methodology for recovery of these coststhis case are yet to be
unlawful
retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. The Company believes that
the elimination of the purchase deficiency method of recovery
will affect the timing for recovery of take-or-pay charges and
shift the allocations among Pipeline Corporation's customers
(including the Company) but that all such charges should be
ultimately recovered. The Supreme Court decision establishes a
principle of law that will provide a basis for full recovery by
the Company, as well as Pipeline Corporation, of these costs.
E. On July 3, 1989 the PSC granted the Company approximately
$21.9 million of a requested $27.2 million annual increase in
retail electric revenues based upon an allowed return on common
equity of 13.25%. The Consumer Advocate appealed the decision to
the Supreme Court which, on August 31, 1992, found that the
evidenceresolved in the record of that case did not support a return on
common equity higher than 13.0% and remanded to the PSC a portion
of its July 1989 order for a determination of the proper return
on common equity consistent with the Supreme Court's opinion. On
January 19, 1993 the PSC issued an order allowing a return on
common equity of 13.0%, approving a refund based on the
difference in rates created by the difference between the 13.0%
and the 13.25% return on common equity and making other non-
material adjustments to the calculation of cost-of-service. The
total refund, before interest and income taxes, was approximately
$14.6 million, and was charged against 1992 "Electric Revenues."
The refund plus interest was made during 1993.
F. On November 28, 1989 the PSC granted the Company an
increase in firm retail natural gas rates, effective November 30,
1989, designed to increase annual revenues by $10.1 million, or
89.5% out of the requested increase of approximately $11.3
million. In its order the PSC authorized a 12.75% return on
common equity. The Consumer Advocate appealed to the Supreme
Court which on August 31, 1992 remanded the order to the PSC for
redetermination of the proper amount of litigation expenses to
include in the test period. In January 1993 the PSC reduced the
amount of litigation expense and ordered a refund totaling
approximately $163,000 which was charged against 1992 "Gas
Revenues." The refund was made during 1993.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 19941996 through 19982000
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1994 $13,7191996 $ 36,033 1999 $ 17,663
1997 $26,345
1995 28,94333,252 2000 117,668
1998 31,325
1996 64,146114,483
Approximately $10.9$17.3 million of the current portion of long-
termlong-term debt
for 1993payable 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.
During 1993 certain issues45
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 Company's First and
Refunding Mortgage Bonds were redeemed and replaced with First
Mortgage Bonds.
42
Pipeline Corporation's two principal gas suppliers have
incurred liabilitieslines of credit allow commercial paper in excess of
$100 million to gas producers under take-or-pay
provisionsbe classified as long-term debt. The Company had
outstanding commercial paper of gas supply contracts. The FERC has accepted
filings allowing these pipeline suppliers to recover portions of
such take-or-pay liabilities from their customers, including
Pipeline Corporation, through volumetric surcharges in gas rates
and through direct billings.
The Company's liability to Pipeline Corporation for its
proportionate share of take-or-pay costs was approximately $1.6$111.2 million at December 31,
19931994, of which is included in Accounts
Payable - Affiliated Companies. The Company is paying this
amount plus interest (9.4%)$11.2 million was reclassified to Pipeline Corporation over a five-
year period which began June 1989. The Company recovers these
costs from its customers through the purchased gas adjustment
(PGA) provisions in its rates.
The Company's take-or-pay liability to Pipeline Corporation
will likely be increased due to the Supreme Court decision dated
December 14, 1992 (see Note 2D). The Company anticipates that
any such increase will be recovered through the PGA.long-term debt.
Certain outstanding long-term debt of an affiliated
company (approximately $35.9 million at both December 31, 19931995
and 1992 respectively)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, 1996.1998. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $75$125 million that may
be outstanding at any time.
Commercial paper outstanding totaled $36.8$76.8 million and $55.7$50.6
million at December 31, 19931995 and 19921994 at weighted average
interest rates of 3.47%5.76% and 3.81%6.06%, respectively.
43
5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not
Subject to
Purchase or Sinking Funds):COMMON EQUITY:
The changes in "Stockholders' Investment" (Including
Preferred Stock Not Subject to Purchase or Sinking Funds) during
1993, 19921995, 1994 and 19911993 are summarized as follows:
Common Preferred Thousands
Shares Shares of Dollars
Balance December 31, 1990 40,296,147 322,877 $847,400
Changes in Retained Earnings:
Net Income 122,836
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,706)
Common Stock (97,000)
Other 2
Balance December 31, 1991 40,296,147 322,877 866,532
Changes in Retained Earnings:
Net Income 102,163
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,474)
Common Stock (99,291)
Equity Contributions from Parent 126,838
Balance December 31, 1992 40,296,147 322,877 989,768$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 $1,077,3611,077,361
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 mayunder
certain circumstances could limit the payment of cash dividends on common
stock. In addition, with respect to hydroelectric projects, the Federal
Power Act may requirerequires the appropriation of a portion of the earnings
therefrom. At December 31, 19931995 approximately $10.6$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.
At any time when dividends have not been paid in full or
declared and set apart for payment on all series of preferred
stock, the Company may not redeem any shares of preferred stock
(unless all shares of preferred stock then outstanding are
redeemed) or purchase or otherwise acquire for value any shares
of preferred stock except in accordance with an offer made to all
holders of preferred stock. The Company may not redeem any
shares of preferred stock (unless all shares of preferred stock
then outstanding are redeemed) or purchase or otherwise acquire
for value any shares of preferred stock (except out of monies set
aside as purchase funds or sinking funds for one or more series
of preferred stock) at any time when it is in default under the
provisions of the purchase fund or sinking fund for any series of
preferred stock.
44
The aggregate annual amounts of purchase fund or sinking fund requirements
for preferred stock for the years 19941996 through 19982000 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1994 $2,5041996 $2,439 1999 $2,440
1997 $2,440
1995 2,5152,440 2000 2,440
1998 2,440
1996 2,482
The changes in "Total Preferred Stock (Subject to Purchase or Sinking
Funds)" during 1993, 19921995, 1994 and 19911993 are summarized as follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1990 1,050,201 $ 64,460
Shares Redeemed:
$100 par value (628) (63)
$50 par value (51,169) (2,559)
Balance December 31, 1991 998,404 61,838
Shares Redeemed:
$100 par value (6,098) (610)
$50 par value (51,777) (2,589)
Balance December 31, 1992 940,529 $ 58,639
Shares Redeemed:
$100 par value (7,374) (737)
$50 par value (51,187) (2,558)
Balance December 31, 1993 881,968 55,344
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 $ 55,34448,682
7. INCOME TAXES:
Total income tax expense for 1993, 19921995, 1994 and 19911993 is as follows:
1995 1994 1993 1992 1991
(Thousands of Dollars)
Current taxes:
Federal $ 94,137 $66,597 $60,577
$62,147 $36,594
State 14,265 9,505 6,822 7,852 4,833
Total current taxes 108,402 76,102 67,399 69,999 41,427
Deferred taxes, net:
Federal (7,319) 7,727 12,197
(16,274) 25,212
State (603) 2,118 4,387 (322) 4,469
Total deferred taxes (7,922) 9,845 16,584 (16,596) 29,681
Investment tax credits:
Amortization of amounts
deferred (credit) (3,245) (3,245)(3,230) (3,231) (3,245)
Total income tax expense $ 97,250 $82,716 $80,738
$50,158 $67,863
4547
TotalThe difference in actual income taxes differand the income taxes
calculated from amounts computed by applyingthe application of the statutory Federal income
tax rate of 35%(35% for 19931995, 1994 and 34% for
1992 and 19911993) to pretax income is
reconciled as follows:
1993 1992 1991
(Thousands of Dollars)
Net income $145,968 $102,163 $122,836
Total income tax expense:
Charged to operating expenses 81,280 51,382 68,543
Charged (credited) to other income (542) (1,224) (680)
Total pretax income $226,706 $152,321 $190,699
Income taxes on above at statutory Federal
income tax rate $ 79,347 $ 51,789 $ 64,838
Increases (decreases) attributable to:
Allowance for funds used during construction
(excluding nuclear fuel) (2,624) (1,556) (1,009)
Deferred return on plant investment,
net of amortization 1,486 1,444 1,444
Depreciation differences 2,531 2,356 1,666
Amortization of investment tax credits (3,245) (3,245)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 4,970 6,140
Deferred income tax flowback at
higher than statutory rates (3,310) (3,647) (3,641) (4,914) (2,768)
Other differences, net 229 (1,811) (402) (686) 797
Total income tax expense $ 97,250 $ 82,716 $ 80,738 $ 50,158 $ 67,863
The Omnibus Budget Reconciliation Act was signed into law on
August 10, 1993, increasing the corporate tax rate from 34% to 35%
effective January 1, 1993. This impact of this change on the
Company's financial position and results of operation was not
material.
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $471.8$468.9
million at December 31, 19931995 and $485.8 million at December 31,
1994 determined in accordance with Statement No. 109 (see Note
1I)1J) are as follows (thousandsfollows:
1995 1994
(Thousands of dollars):
1993Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 52,31048,512 $ 50,513
Cycle billing 15,08419,143 17,521
Nuclear operations expenses 4,9083,755 206
Deferred compensation programs 5,2655,562 5,450
Other postretirement benefits 1,631
Injuries and damages 7246,371 3,187
Other 3,8082,929 3,627
Total deferred tax assets 83,73086,272 80,504
Deferred tax liabilities:
Accelerated depreciationProperty plant and amortization 526,540equipment 520,294 533,394
Pension expense 14,191 9,022
Reacquired debt 7,574
Property taxes 6,068
Pension expense 6,266
Nuclear system maintenance 2,965
Early retirement programs 1,961
Nuclear decontamination fund 1,4176,680 7,146
Research and experimentation 6,196 2,276
Other 2,7327,801 14,458
Total deferred tax liabilities 555,523555,162 566,296
Net deferred tax liability $471,793
46
"Total deferred taxes" charged (credited) to income tax expense result from
timing differences in recognition of the following items:
1992 1991
(Thousands of Dollars)
Charged (credited) to expense:
Accelerated depreciation
and amortization $ (5) $22,053
Deferred fuel accounting (2,947) 461
Property taxes 493 1,608
Cycle billing (1,381) 3,608
Nuclear refueling accrual (4,430) 2,052
Electric rate refund (6,571) -
Injuries and damages (1,377) -
Other, net (378) (101)
Total deferred taxes $(16,596) $29,681$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 19911992 Federal income
tax returns. No adjustmentsAdjustments 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 INSTRUMENTSINSTRUMENTS:
The carrying amounts and estimated fair values of the
Company's financial instruments at December 31, 19931995 and 19921994 are
as follows:
1993 19921995 1994
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
Cash and temporary cash
investments $ 1936,798 $ 1936,798 $ 24,302346 $ 24,302346
Investments 62 62 62 6261 61 61 61
Liabilities:
Short-term borrowings 1,011 1,011 33 33
Total81 81 100,000 100,000
Notes payable - affiliated
companies - - 19,409 19,409
Long-term debt (including
advances from affiliated companies) 1,112,321 1,194,522 962,193 1,006,636
Total1,315,412 1,412,213 1,264,233 1,195,023
Preferred stock (subject
to purchase or sinking funds) 55,344 51,618 58,639 53,77148,682 46,603 51,946 49,348
The information presented herein is based on pertinent
information available to the Company as of December 31, 19931995 and
1992.1994. 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, 1993,1995, 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 forof 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.
47
The fair value of preferred stock (subject to purchase or
sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in
an actual sale or settlement have not been taken into
consideration.
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, 1993, 19921995, 1994 and 19911993 and for the years
then ended are as follows:
1995 1994 1993 1992 1991
(Millions of dollars)
Authorized lines of credit at year end $127.0 $119.9 $121.7year-end $165.0 $165.0 $212.0
Unused lines of credit at year-end $127.0 $119.9 $121.7
Short-term borrowings (including
commercial paper) during the year:
Maximum outstanding $126.0 $ 95.3 $130.4
Average outstanding $ 56.0 $ 40.9 $ 64.5
Weighted daily average interest rates:
Bank loans 3.24% 3.49% 7.69%
Commercial paper 3.13% 3.69% 6.31%$165.0 $165.0 $212.0
Short-term borrowings outstanding at
year-end:
Commercial paper $ 1.080.5 $100.0 $ - $ -1.0
Weighted average interest rate 3.50% - -
Bank loans $ - $ - $ -
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 in Orangeburg County.Carolina.
Construction of the plant started in November 1992. Commercial
operation began in November 1992 and commercial operation is expected in late 1995 or
earlyJanuary 1996. The estimated pricecost of the Cope plant,
excluding financing
costs and AFC, but including an allowance for escalation, is $450$410.9 million. In addition, the transmission
lines for interconnection with the Company's system are expected to cost $26$22.5
million.
48
Under the Duke/Fluor Daniel contract the Company must make specified
monthly minimum payments. These minimum payments do not include amounts for
inflation on a portion of the contract which is subject to escalation
(approximately 34% of the total contract amount). The aggregate amount of
such
required minimum payments remaining at December 31, 19931995 is as follows
(in thousands):
1994 $168,152
1995 59,766
1996 5,603
Total $233,521$4.2
million due in 1996. Through December 31, 19931995 the Company had
paid $142.0$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 $9.4$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 not exceed approxi-
matelybe 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 $1.4$1.9 billion for any
losses in excess of $500 million pursuant
to existing primary coverages (with ANI) onat Summer Station. The Company pays annual premiums and,
in addition, could be assessed a retroactive premium not to
exceed 7 1/2 times its annual premium in the event of property
damage loss to any nuclear generating facilities covered by NEIL.under
the NEIL program. Based on the current annual premium, this
retroactive premium would not exceed approximately $8.1$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 materiallymaterial adverse impact on the Company's
financial position.position and results of operations.
50
C. Litigation
In January 1994 the Company, acting on behalf of itself and the PSA (as
co-owners of Summer Station), reached a settlement with Westinghouse
Electric Corporation (Westinghouse) resolving a dispute involving steam
generators provided by Westinghouse to Summer Station which are defective in
design, workmanship and materials. Terms of the settlement are confidential
by agreement of the parties and order of the court. The Company had filed
an action in May 1990 against Westinghouse in the U. S. District Court
for South Carolina; an order dismissing this suit was issued on
January 12, 1994.
D. Environmental
As described in Note 1L,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, an
estimate isestimates are made of the amount of expenditures,cost, 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 differ from the original estimates.
Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations; such amounts
have beenare deferred and are being amortized and recovered through rates
over a ten-year period.
49period 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, 1993, 19921995, 1994 and 19911993 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 $940,547$ 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) $209,597$ 209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585
Less - Interest charges 79,936
Net income $ 145,968
Capital expenditures:
Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934
Total $ 300,620
Identifiable assets at
December 31, 1993:
Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603
Inventories 66,181 2,526 463 69,170
Total $2,511,647 $180,990 $2,136 2,694,773
Assets utilized for overall Company operationsOther assets 495,166
Total assets $3,189,939
5053
1992
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 829,938 $160,820 $ 3,623 $ 994,381
Operating expenses,
excluding depreciation
and amortization 572,234 133,611 9,205 715,050
Depreciation and
amortization 87,367 9,534 163 97,064
Total operating expenses 659,601 143,145 9,368 812,114
Operating income (loss) $ 170,337 $ 17,675 $(5,745) 182,267
Add - Other income, net 3,006
Less - Interest charges 83,110
Net income $ 102,163
Capital expenditures:
Identifiable $ 223,697 $ 10,409 $ 346 $ 234,452
Utilized for overall Company operations 8,877
Total $ 243,329
Identifiable assets at
December 31, 1992:
Utility plant, net $2,271,895 $177,309 $ 1,240 $2,450,444
Inventories 68,435 2,967 481 71,883
Total $2,340,330 $180,276 $ 1,721 2,522,327
Assets utilized for overall Company operations 368,626
Total assets $2,890,953
51
1991
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 867,685 $ 150,788 $ 3,869 $1,022,342
Operating expenses,
excluding depreciation
and amortization 596,466 128,529 9,023 734,018
Depreciation and
amortization 82,503 8,969 146 91,618
Total operating expenses 678,969 137,498 9,169 825,636
Operating income (loss) $ 188,716 $ 13,290 $ (5,300) 196,706
Add - Other income, net 3,283
Less - Interest charges 77,153
Net income $ 122,836
Capital expenditures:
Identifiable $ 191,218 $ 16,029 $ 89 $ 207,336
Utilized for overall Company operations 7,967
Total $ 215,303
Identifiable assets at
December 31, 1991:
Utility plant, net $2,154,221 $ 176,570 $ 1,073 $2,331,864
Inventories 69,316 2,553 476 72,345
Total $2,223,537 $ 179,123 $ 1,549 2,404,209
Assets utilized for overall Company operations 344,371
Total assets $2,748,580
52
12. SUPPLEMENTARY INCOME STATEMENT INFORMATION:
Maintenance expense (including repairs) and provision for depreciation
and amortization of utility plant are shown separately in the accompanying
consolidated statements of income, except for amounts charged to clearing
and other accounts, which amounts are not significant. Advertising expenses
are not material and there were no royalties. Taxes other than income taxes
are as follows (amounts for nonutility operations are not significant):
December 31,
1993 1992 1991
(Thousands of Dollars)
State electric generation tax $ 4,056 $ 4,299 $ 3,638
General property taxes 47,624 47,320 44,567
Special state utility license 1,814 1,965 1,595
Federal social security taxes 8,534 8,113 7,463
State gross receipts tax 2,871 3,427 2,734
Other taxes 462 470 942
Total charged to operating expenses $65,361 $65,594 $60,939
13. QUARTERLY FINANCIAL DATA (UNAUDITED):
19931995
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $279,241 $244,485 $329,673 $265,034 $1,118,433$308,759 $275,139 $339,937 $287,252 $1,211,087
Operating income 55,274 38,934 79,363 45,748 219,31967,189 53,153 87,023 48,489 255,854
Net Income 36,820 21,327 61,032 26,789 145,968
199245,249 30,870 65,040 28,026 169,185
1994
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $263,576 $222,097 $270,937 $237,771 $994,381$313,321 $263,033 $327,066 $277,854 $1,181,274
Operating income 49,805 33,452 58,149 40,861 182,26763,520 43,316 79,133 44,449 230,418
Net Income 30,055 13,528 36,747 21,833 102,16345,340 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
SCHEDULE V
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Property, Plant and Equipment
Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 2,526,525 $ 387,277 $ $ 2,913,802
Production Plant - Steam 419,861,153 48,342,749 $23,766,610 (58,121) 444,379,171
Production Plant - Nuclear 901,572,157 6,351,974 2,080,492 905,843,639
Production Plant - Hydraulic 252,749,355 1,300,683 57,399 (16,026) 253,976,613
Other Production 63,281,062 866,307 1,500 (899,820) 63,246,049
Transmission 307,889,993 14,609,788 218,883 (642,210) 321,638,688
Distribution 909,829,946 71,365,534 6,417,737 622,432 975,400,175
General 95,416,815 7,591,100 4,188,810 726,828 99,545,933
Construction Work in Progress 203,255,081 116,265,554 319,520,635
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 3,157,318,978 267,080,966 36,731,431 (266,917) 3,387,401,596
Gas Utility Plant:
Intangible Plant 2,002 2,002
Production Plant 12,404,326 124,400 364,632 12,164,094
Distribution 233,452,324 9,334,575 244,443 242,542,456
General 17,816,286 752,470 714,102 (55,270) 17,799,384
Construction Work in Progress 2,154,465 1,462,713 3,617,178
Total Gas Plant 265,829,403 11,674,158 1,325,179 (55,270) 276,123,112
Transit Utility Plant:
Plant in Service 3,286,740 820,846 338,083 3,769,503
Construction Work In Progress 346,440 (217,070) 129,370
Total Transit Plant 3,633,180 603,776 338,083 3,898,873
Common Utility Plant:
Plant in Service 65,124,200 9,842,345 512,645 (1,650,001) 72,803,899
Construction Work in Progress 11,318,260 4,091,970 15,410,230
Total Common Plant 76,442,460 13,934,315 512,645 (1,650,001) 88,214,129
Nuclear Fuel, Net 39,916,340 7,325,982 (18,155,649) 29,086,673
Total Utility Plant 3,543,140,361 300,619,197 38,907,338 (20,127,837) 3,784,724,383
Nonutility Property 13,360,800 249,267 16,729 6,403 13,599,741
Total Property, Plant and
Equipment $3,556,501,161 $300,868,464 $38,924,067 $(20,121,434) $3,798,324,124
(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.
54
SCHEDULE V
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Property, Plant and Equipment
Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 1,745,368 $ 668,802 $ 112,355 $ 2,526,525
Production Plant - Steam 386,509,775 39,281,836 $ 6,311,184 380,726 419,861,153
Production Plant - Nuclear 902,210,500 10,513,580 11,089,182 (62,741) 901,572,157
Production Plant - Hydraulic 252,263,540 729,289 11,087 (232,387) 252,749,355
Other Production 60,580,141 3,495,438 72,541 (721,976) 63,281,062
Transmission 284,885,248 23,378,760 345,830 (28,185) 307,889,993
Distribution 836,231,555 80,261,671 6,726,789 63,509 909,829,946
General 86,645,581 12,212,253 2,218,502 (1,222,517) 95,416,815
Construction Work in Progress 171,497,768 31,757,313 203,255,081
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 2,983,506,367 202,298,942 26,775,115 (1,711,216) 3,157,318,978
Gas Utility Plant:
Intangible Plant 2,002 2,002
Production Plant 11,729,301 677,519 (2,494) 12,404,326
Distribution 222,086,762 12,319,371 953,809 233,452,324
General 17,254,519 832,364 455,798 185,201 17,816,286
Construction Work in Progress 5,574,900 (3,420,435) 2,154,465
Total Gas Plant 256,647,484 10,408,819 1,409,607 182,707 265,829,403
Transit Utility Plant:
Plant in Service 3,626,110 25,203 364,573 3,286,740
Construction Work In Progress 25,422 321,018 346,440
Total Transit Plant 3,651,532 346,221 364,573 3,633,180
Common Utility Plant:
Plant in Service 59,209,415 6,427,058 564,596 52,323 65,124,200
Construction Work in Progress 8,868,396 2,449,864 11,318,260
Total Common Plant 68,077,811 8,876,922 564,596 52,323 76,442,460
Nuclear Fuel, Net 41,708,502 21,398,027 (23,190,189) 39,916,340
Total Utility Plant 3,353,591,696 243,328,931 29,113,891 (24,666,375) 3,543,140,361
Nonutility Property 13,337,632 222,651 18,235 (181,248) 13,360,800
Total Property, Plant and
Equipment $3,366,929,328 $243,551,582 $29,132,126 $(24,847,623) $3,556,501,161
(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.
55
SCHEDULE V
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Property, Plant and Equipment
Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 1,498,215 $ 247,153 $ 1,745,368
Production Plant - Steam 375,757,013 11,221,353 $ 2,107,137 $ 1,638,546 386,509,775
Production Plant - Nuclear 892,803,058 11,400,155 1,990,340 (2,373) 902,210,500
Production Plant - Hydraulic 246,061,917 6,234,421 18,421 (14,377) 252,263,540
Other Production 24,719,968 36,664,254 151,891 (652,190) 60,580,141
Transmission 268,810,887 17,218,465 756,709 (387,395) 284,885,248
Distribution 767,262,239 75,701,545 6,388,466 (343,763) 836,231,555
General 78,793,633 10,608,299 2,751,716 (4,635) 86,645,581
Construction Work in Progress 166,273,512 5,224,256 171,497,768
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 2,822,917,333 174,519,901 14,164,680 233,813 2,983,506,367
Gas Utility Plant:
Intangible Plant 2,002 2,002
Production Plant 12,165,685 132,278 568,662 11,729,301
Distribution 207,249,333 15,419,520 582,091 222,086,762
General 16,549,092 2,010,529 1,308,383 3,281 17,254,519
Construction Work in Progress 7,108,395 (1,533,495) 5,574,900
Total Gas Plant 243,074,507 16,028,832 2,459,136 3,281 256,647,484
Transit Utility Plant:
Plant in Service 3,834,731 109,676 318,297 3,626,110
Construction Work In Progress 45,951 (20,529) 25,422
Total Transit Plant 3,880,682 89,147 318,297 3,651,532
Common Utility Plant:
Plant in Service 53,402,648 7,485,224 463,637 (1,214,820) 59,209,415
Construction Work in Progress 5,522,233 3,346,163 8,868,396
Total Common Plant 58,924,881 10,831,387 463,637 (1,214,820) 68,077,811
Nuclear Fuel, Net 43,394,098 16,697,735 (18,383,331) 41,708,502
Total Utility Plant 3,172,191,501 218,167,002 17,405,750 (19,361,057) 3,353,591,696
Nonutility Property 15,002,658 632,077 496,481 (1,800,622) 13,337,632
Total Property, Plant and
Equipment $3,187,194,159 $218,799,079 $17,902,231 $(21,161,679) $3,366,929,328
(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.
56
SCHEDULE VI
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 510,230 $ 215,400 $ 725,630
Production Plant - Steam 183,320,992 11,748,848 $26,118,661 168,951,179
Production Plant - Nuclear 258,546,891 27,136,078 4,336,461 281,346,508
Production Plant - Hydraulic 56,833,113 3,708,900 387,290 60,154,723
Other Production 20,965,067 1,992,545 48,970 22,908,642
Transmission 94,236,791 7,748,900 610,744 101,374,947
Distribution 274,166,096 29,477,600 7,264,838 296,378,858
General 35,824,269 6,112,419 3,690,790 38,245,898
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 925,340,340 88,140,690 42,457,754 971,023,276
Gas Utility Plant:
Production Plant 4,051,584 344,400 118,173 4,277,811
Distribution 78,240,161 8,798,400 353,335 86,685,226
General 6,229,475 939,849 473,341 6,695,983
Total Gas Plant 88,521,220 10,082,649 944,849 97,659,020
Transit Utility Plant 2,393,120 167,000 333,808 2,226,312
Common Utility Plant:
Common Plant 21,919,678 2,711,444 395,972 24,235,150
Intangible Plant 1,764,900 622,600 2,387,500
Total Common Plant 23,684,578 3,334,044 395,972 26,622,650
Total Utility Plant 1,039,939,258 101,724,383 44,132,383 1,097,531,258
Nonutility Property 818,636 150,000 16,729 951,907
Total Property, Plant and
Equipment $1,040,757,894 $101,874,383 $ 44,149,112 $1,098,483,165
(*) After deduction of net salvage.
57
SCHEDULE VI
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 483,330 $ 26,900 $ 510,230
Production Plant - Steam 181,467,097 9,327,525 $ 7,473,630 183,320,992
Production Plant - Nuclear 244,349,995 26,159,978 11,963,082 258,546,891
Production Plant - Hydraulic 53,551,159 3,474,075 192,121 56,833,113
Other Production 18,442,317 2,636,400 113,650 20,965,067
Transmission 87,812,534 7,068,000 643,743 94,236,791
Distribution 251,465,003 28,531,200 5,830,107 274,166,096
General 32,484,258 5,140,301 1,800,290 35,824,269
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 870,992,584 82,364,379 28,016,623 925,340,340
Gas Utility Plant:
Production Plant 3,722,784 328,800 4,051,584
Distribution 70,865,818 8,373,600 999,257 78,240,161
General 5,489,388 976,408 236,321 6,229,475
Total Gas Plant 80,077,990 9,678,808 1,235,578 88,521,220
Transit Utility Plant 2,579,278 146,500 332,658 2,393,120
Common Utility Plant:
Common Plant 18,020,122 4,033,463 133,907 21,919,678
Intangible Plant 1,160,900 604,000 1,764,900
Total Common Plant 19,181,022 4,637,463 133,907 23,684,578
Total Utility Plant 972,830,874 96,827,150 29,718,766 1,039,939,258
Nonutility Property 366,216 148,100 (304,320) 818,636
Total Property, Plant and
Equipment $973,197,090 $ 96,975,250 $ 29,414,446 $1,040,757,894
(*) After deduction of net salvage.
58
SCHEDULE VI
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 282,630 $ 200,700 $ 483,330
Production Plant - Steam 176,597,113 8,986,800 $ 4,116,816 181,467,097
Production Plant - Nuclear 220,460,998 25,905,578 2,016,581 244,349,995
Production Plant - Hydraulic 50,787,917 3,478,800 715,558 53,551,159
Other Production 17,204,322 1,591,396 353,401 18,442,317
Transmission 82,003,719 6,616,800 807,985 87,812,534
Distribution 232,605,806 26,114,400 7,255,203 251,465,003
General 29,725,228 5,114,200 2,355,170 32,484,258
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 810,604,624 78,008,674 17,620,714 870,992,584
Gas Utility Plant:
Production Plant 3,949,910 334,800 561,926 3,722,784
Distribution 63,862,085 7,863,600 859,867 70,865,818
General 5,547,775 981,700 1,040,087 5,489,388
Total Gas Plant 73,359,770 9,180,100 2,461,880 80,077,990
Transit Utility Plant 2,674,599 130,100 225,421 2,579,278
Common Utility Plant:
Common Plant 14,793,032 3,723,000 495,910 18,020,122
Intangible Plant 577,700 583,200 1,160,900
Total Common Plant 15,370,732 4,306,200 495,910 19,181,022
Total Utility Plant 902,009,725 91,625,074 20,803,925 972,830,874
Nonutility Property 635,832 187,000 456,616 366,216
Total Property, Plant and
Equipment $902,645,557 $ 91,812,074 $ 21,260,541 $973,197,090
(*) After deduction of net salvage.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
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
The directors listed below were elected April 29, 1993 to hold
office until the next annual meeting of the Company's stockholder
on April 28, 1994.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 50 Since September 30, 1988, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).
Since January 12, 1988, Chairman and Chief
Executive Officer of Amick Processing, Inc.
and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia, SC.
William B. Bookhart, Jr. 52 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 64 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC;
South Carolina National Corporation,
Columbia, SC; The Seibels Bruce Group,
Inc., Columbia, SC.
Hugh M. Chapman 61 Since January 1, 1992, Chairman of
(1988) NationsBank South, Atlanta, GA (a division
of NationsBank Corporation, bank holding
company).
From September 1, 1990 to December 31, 1991,
Vice Chairman and Director, C&S/Sovran
Corporation, Atlanta, GA.
Prior to September 1, 1990, President and
Director, Citizens & Southern
Corporation, Atlanta, GA and Chairman
of the Board, Citizens & Southern
South Carolina Corporation, Columbia,
SC.
Director, SCANA Corporation, Columbia, SC.
60
Name and Year First
Became Director Age Principal Occupation; Directorships
James B. Edwards, D.M.D. 66 President and Professor of Maxillofacial
(1986) Surgery, Medical University of South
Carolina.
U.S. Secretary of Energy from January 1981 to
November 1982.
Governor of South Carolina, 1975-1979.
Director, Phillips Petroleum Co.,
Bartlesville, OK; Brendle's,
Inc., Elkin, NC; Chemical Waste
Management, Inc., Chicago, IL; Imo
Industries, Inc., Lawrenceville, NJ;
South Carolina National Corporation,
Columbia, SC; South Carolina National Bank,
Columbia, SC; National Data Corporation,
Atlanta, GA; Encyclopedia Britannica,
Chicago, IL; Communications Satellite
Corporation;
SCANA Corporation, Columbia, SC.
Elaine T. Freeman 58 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization).
Director, SCANA Corporation, Columbia, SC.
Lawrence M. Gressette, Jr. 62 Since February 1, 1990, Chairman of the
(1987) Board, Chief Executive Officer and
President of SCANA Corporation and
Chairman of the Board and Chief
Executive Officer of all SCANA
subsidiaries, including the Company.
From September 1, 1985 to January 31, 1990,
President of SCANA Corporation.
From January 1, 1988 to February 21, 1989,
President and Treasurer of SCANA
Corporation.
From May 1, 1987 to January 31, 1990, Vice
Chairman of the Company.
Director, Wachovia Corporation, Winston-
Salem, NC; SCANA Corporation, Columbia, SC.
Benjamin A. Hagood 66 Since January 1, 1993, Chairman of the Board,
(1974) William M. Bird and Company, Inc.,
Charleston, SC (wholesale distributor of
floor covering material).
Prior to January 1, 1993, President and
Director, William M. Bird and Company,
Inc., Charleston, SC.
61
Name and Year First
Became Director Age Principal Occupation; Directorships
Benjamin A. Hagood Director, SCANA Corporation, Columbia, SC.
(continued)
W. Hayne Hipp 54 For more than five years, President and
(1983) Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance
and broadcasting holding company).
Director, The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC; SCANA Corporation,
Columbia, SC.
Bruce D. Kenyon 51 Since November 12, 1990, President and Chief
(1991) Operating Officer of the Company.
From April 4, 1988 to November 9, 1990,
Senior Vice President-Division Operations,
Pennsylvania Power and Light Company,
Allentown, PA.
Director, SCANA Corporation, Columbia, SC.
F. Creighton McMaster 64 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor
of petroleum products).
Director, First Union National Bank of
South Carolina, Greenville, SC; SCANA
Corporation, Columbia, SC.
Henry Ponder, Ph.D. 65 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Third National Bank, Nashville,
TN; SCANA Corporation, Columbia, SC.
John B. Rhodes 63 For more than five years, Chairman and
(1967) Chief Executive Officer, Rhodes Oil
Company, Inc., Walterboro, SC (distributor
of petroleum products).
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 47 For more than five years, Senior Vice
(1991) President, Chief Financial Officer and
Controller of SCANA Corporation.
Since August 28, 1991 Chief Financial Officer
of the Company.
Director, SCANA Corporation, Columbia, SC.
62
Name and Year First
Became Director Age Principal Occupation; Directorships
E. Craig Wall, Jr. 56 For more than five years, President and
(1982) Director, Canal Industries, Conway, SC
(forest products industry).
Director, Sonoco Products Company,
Hartsville, SC; Ruddick Corporation,
Charlotte, NC; Blue Cross/Blue Shield of
South Carolina, Columbia, SC; SCANA
Corporation, Columbia, SC.
John A. Warren 69 Since February 1, 1990, Chairman of the
(1982) Board Emeritus of SCANA Corporation. Since
April 6, 1989, Chairman of the Board of
Palmetto Seed Capital Corporation,
Columbia, SC (venture capital corporation).
From April 23, 1986 to January 31, 1990,
Chairman of the Board and Chief Executive
Officer of SCANA Corporation and
subsidiaries.
Director, The Liberty Corporation,
Greenville, SC; SCANA Corporation,
Columbia, SC.
63
EXECUTIVE OFFICERS OF THE COMPANY
The executive officers are elected at the annual
organizational meeting of the Board of Directors and hold office
until the next such organizational meeting, unless the Board of
Directors shall otherwise determine, or unless a resignation is
submitted.
Positions Held During
Name Age Past Five Years Dates
L.M. Gressette, Jr. (1) 62 Chairman of the Board and
Chief Executive Officer 1990-present
Vice Chairman of the Board *-1990
B.D. Kenyon (1) 51 President and Chief
Operating Officer 1990-present
Senior Vice President -
Division Operations,
Pennsylvania Power and
Light Company 1988-1990
W.B. Timmerman (1) 47 Chief Financial Officer 1991-present
Senior Vice President,
Chief Financial Officer
and Controller, SCANA 1988-present
G.J. Bullwinkel, Jr. 45 Senior Vice President-
Fossil & Hydro Production 1993-present
Senior Vice President-
Production 1991-1992
Vice President-Customer
Relations, Southern Division *-1991
R.W. Stedman 52 Senior Vice President-
Administrative Support
Group 1993-present
Senior Vice President-
Administration 1988-1992
*Indicates position held at least since March 1, 1989
(1) Also an executive officer of SCANA
64
Positions Held During
Name Age Past Five Years Dates
J.H. Young, Jr. 57 Senior Vice President-
Customer Relations 1988-present
W.A. Darby 48 Vice President-Gas Operations *-present
P.T. Smith 46 Vice President and General
Counsel - Rates and Regulatory
Affairs 1992-present
Vice President - Regulatory
Affairs 1991-1992
Vice President - Rates,
Purchasing & Regulatory Affairs *-1991
J.E. Addison 33 Vice President and Controller 1992-present
Controller 1991
Partner - Hughes, Boan &
Addison, CPA's 1990-1991
Manager - Deloitte & Touche *-1990
*Indicates position held at least since March 1, 1989
There is no family relationship between any of the persons named in
response to Item 10.
65
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.
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to compensation paid
or accrued by SCANA Corporation and its subsidiaries, including the Company,
during the years 1993, 1992 and 1991 to the Chief Executive Officer of the
Company and to each of the other four most highly compensated executive officers
of the Company during 1993 who were serving as executive officers of the Company
at the end of 1993.
SUMMARY COMPENSATION TABLE
Name and principal positionPrincipal Year Annual Compensation Long-Term
All other4Position Compensation
compensa-
tion ($)(1) (2)
Salary Bonus Other Payouts
Salary Bonus1 Other annual2
($) ($) compensa- LTIP3Annual
Compen-
sation
($) (3) (4)
LTIP All Other
Payouts Compensa-
($) tion ($) payouts ($)
(a) (b) (c) (d) (e) (h) (i)
L. M. Gressette, Jr. 1993 383,5575 186,615 57,375 266,007 23,0131995 449,246(5) 197,500 65,779 390,156 26,955
Chairman of the Board, 1992 368,4261994 416,609 0 60,488 82,151 22,104
President, Chief Executive 1991 339,904 144,000 61,000
Officer and Director -
SCANA Corporation
and the Company and
Chairman of the2,255 173,375 24,996
Board and Chief 1993 383,557 186,615 61,699 266,007 23,013
Executive Officer -
all SCANA subsidiaries,
including the Company
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 90,09099,090 4,201 125,792 17,866
President and Chief Operating 1992 291,355 0 3,265 46,250 17,481
Officer 1991 262,925 81,450 0
Director - SCANA Corporation
and the Company
W. B. Timmerman 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 and 1992 215,8171994 170,828 42,573 762 38,249 9,826
- - Retail Electric 1993 148,705 51,975 1,477 58,489 0
2,303 15,906 12,949
Chief Financial Officer - 1991 187,615 70,950 33,000
SCANA Corporation
Chief Financial Officer
Director - SCANA Corporation
and the Company
J. H. Young 1993 167,566 51,975 1,542 70,508 10,054L. Skolds 1995 176,156 74,151 54 76,128 10,569
Senior Vice President 1992 165,1021994 156,731 42,573 2,146 38,249 9,404
- - Generation 1993 146,438 43,605 4,065 58,489 0
1,084 23,556 9,906
Customer Relations 1991 144,861 45,450 17,000
R. W. Stedman 1993 170,361 51,975 1,107 70,508 10,222
Senior Vice President - 1992 167,259 0 985 23,556 10,036
Administrative Support Group 1991 146,155 45,450 17,000
1______________
(1) Payments under the annual Performance Incentive Plan described hereafter.
2(2) Other annual compensation consists of (i) for Mr. Gressette, perquisites
including compensation related to whole life insurance premiums for those1995
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 individuals
whose perquisites exceeded the lesser of 10% of their salary and bonus or $50,000
and (ii)officers,
payments to cover taxes on benefits.
The perquisites for Mr. Gressette
includes compensation related to the Whole Life Option described hereafter in the
amount of $50,018 for both 1993 and 1992.
3(3) Payments under the long termlong-term Performance Share PlantPlan described hereafter.
4(4) All other compensation includesconsists solely of Company contributions to the SCANA Stock Purchase
Savings Plan ("Savings Plan") and the Supplementary Voluntary Deferral Plan
described hereafterdefined
contribution plans based on the funding formula forapplicable to all
employees of the Company.
5(5) Reflects actual salary paid in 1993.1995. Base salary of $395,000$460,000, became
effective in May of 1993; the 1992 salary of $360,000 was in effect from January to April of
1993.1995.
66
DESCRIPTION OF PLANS
Incentive Compensation
To bring total compensation of officers to market levels,
the Company has two incentive plans:
Annual Performance Incentive Plan
SCANA has annual Performance Incentive Plans for officers of
SCANA and its subsidiaries. The plans promote SCANA's
pay-for-performance philosophy, as well as its goal of
having a meaningful amount of executive pay "at-risk."
Through these plans, financial incentives are provided in
the form of annual cash bonuses that are paid only when
corporate, business unit and individual goals are
achieved.
Short-term incentive awards are targeted below the median of
the market. Executives eligible for these plans are
assigned threshold, target and maximum bonus levels as a
percentage of salary level. Bonuses earned are based on
the level of the preestablished goals achieved. Award
payouts may increase to a maximum of 1.5 times target, if
Company performance exceeds the goals established. Even
if this were to occur, payouts would still be below the
market median. Award payouts may decrease, generally to a
minimum of one-half the target-level awards, if the
Company's performance is below targeted goals. Awards
earned based on the achievement of preestablished goals
may nonetheless be decreased to zero (as was done in
1992), if the Management Development and Corporate
Performance Committee (Performance Committee) in its
discretion determines that actual results do not warrant
the levels of payouts otherwise earned.
The various plans in which officers of SCANA and its
subsidiaries participate focus generally on short-term
goals affecting profitability, efficiency, quality of
service, customer satisfaction and progress toward SCANA's
strategic objectives for the Company and its other
subsidiaries. New performance categories for officers in
the various plans are established annually. Specific
performance measures, and their weights, also vary from
year to year.
For 1993, the specific measures in each plan, and their
weights, for the officers included in the Summary
Compensation Table on page 66 are described below. The
relationship of performance to payouts for the officers in
each plan also is discussed.
For officers of SCANA, 80% of the total award is based
on corporate Earnings Per Share ("EPS") goals. The
remaining 20% is tied to the achievement of
individual performance goals, and is awarded on a
discretionary basis.
Specific EPS goals are established that correspond
to threshold, target and maximum payouts for the
EPS portion of awards. For 1993, SCANA's EPS
results were sufficient to result in maximum
payouts for that portion of the awards. Individual
performance for corporate officers also was
determined to be sufficient to result in maximum
-level payouts for that portion of the awards.
Awards for officers of the Company are based on
three performance categories: corporate EPS,
numerous corporate and Strategic Business Unit
(SBU) financial and productivity goals, and
additional SBU strategic initiatives (i.e.,
activities that focus on improvements in existing
operating procedures, quality of service and
product, human resources matters, etc.). One-third
of the total award is based on results in each
performance category. Threshold, target and
maximum performance levels are established for each
category; payouts will vary based on the actual
level of performance achieved.
For 1993, the overall Company performance in all
three categories was such that payouts exceeded
target-level awards, but were less than the maximum
awards possible. Although results for the first
two performance categories were above target
performance levels, results in the strategic
initiative category were below that level.60
Long-Term Performance Share Plan
SCANA has aThe long-term Performance Share Plan for officers of SCANA and
its subsidiaries. The long-term Performance
Share Plansubsidiaries measures SCANA's Total Shareholder Return ("TSR")
relative to a group of peer companies (PSP Peer
Group) over a three-year period. The
PSP"PSP Peer GroupGroup" includes 9794 electric and gas utilities, none of which
have annual revenues of less than $100 million.
Total Shareholder ReturnTSR 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. Comparing SCANA's TSR against the TSR of the
PSP Peer Groupcompanies 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.
Target awards are
established at levels slightly below the median of the
market andAwards under this plan represent a significant portion of executives
"at-risk" compensation. But, toTo provide additional incentive for
executives, and to ensure that executives are only rewarded when
shareholders gain, actual payouts may exceed the median of the market
when performance is outstanding.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 cash or a
combination of the two.stock and cash.
For the three-year period from 19911993 through 1993,1995, SCANA's TSR was
at the 79th98th percentile of the PSP Peer Group. This resulted in
payouts in February 19941996 at the maximum
level possible.
The150% of target shares awarded paid in a
combination of the annual Incentive Planstock and the
Performance Share Plan provides an opportunity to bring a
participant's compensation to market levels. The progressive
payout formulas in both plans dictate that above-market pay can
be earned only for better-than-average corporate financial
performance, and that poor performance will result in below-
market pay.
68
cash.
The following table shows the target awards made in 19931995 for
potential payment in 19961998 under the long-term Performance Share Plan,
and estimated future payouts under that plan at threshold, target and
maximum levels.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
LONG-TERM INCENTIVE PLAN
TARGET AWARDS FOR 1993 TO BE PAID IN 1996Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-
BasedPrice-Based Plans
Number of PerformanceUnits or Shares, UnitsPeriod Until
Other PeriodMaturation
Name Rights (#) or Payout
Threshold Target Maximum
Name or Other Rights Until Maturation ($) or (#)
($ or #) ($ or #) (#)($ or Payout
(a) (b) (c) (d) (e) (f)#)
L. M. Gressette, Jr. 4,100 1993 - 1995 1,640 4,100 6,1506,023 1995-1997 2,409 6,023 9,035
B. D. Kenyon 1,810 1993 - 1995 724 1,810 2,7153,700 1995-1997 1,480 3,700 5,550
W. B. Timmerman 1,580 1993 - 1995 632 1,580 2,3703,220 1995-1997 1,288 3,220 4,830
G. J. H. Young 950 1993 - 1995 380 950 1,425
R. W. Stedman 950 1993 - 1995 380 950 1,425Bullwinkel 1,940 1995-1997 776 1,940 2,910
J. L. Skolds 1,940 1995-1997 776 1,940 2,910
Defined Contribution Plans
Under the Savings Plan, most of the Company's employees may
contribute up to 15% of their eligible earnings. The Company
matches each employee's contribution on a dollar-for-dollar basis
up to a maximum of 6% of the participant's eligible earnings as
limited by the Internal Revenue Code (IRC). Both Company and
employee contributions are invested in SCANA's Common Stock.
In addition to the Savings Plan, SCANA has a Supplementary
Voluntary Deferral Plan (the "Supplementary Plan") for certain
highly compensated employees of the Company and other SCANA
subsidiaries. The Supplementary Plan is designed to provide
employees whose participation in the Savings Plan is limited by
the IRC with the ability to contribute and receive matching
contributions in the same percentage as employees generally.
However, unlike the Savings Plan where actual shares of SCANA
Common Stock are acquired, under the Supplementary Plan the
deferred amounts and matches are only accounted for as though
shares of common stock had been purchased.
Defined Benefit Plans61
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 IRCInternal 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, 19941996 and are not subject to any deduction for Social
Security or other offset amounts.
69
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$125,000 35,130 46,840 58,550 70,260 72,595
150,000 42,630 56,840 71,050 85,260 88,220
175,000 50,130 66,840 83,550 100,260 103,845
200,000 57,630 76,840 96,050 115,260 119,470
225,000 65,130 86,840 108,550 130,260 135,095
250,000 72,630 96,840 121,050 145,260 150,720
300,000 87,630 116,840 146,050 175,260 181,970
350,000 102,630 136,840 171,050 205,260 213,220
400,000 117,630 156,840 196,050 235,260 244,470
450,000 132,630 176,840 221,050 265,260 275,720
500,000 147,630 196,840 246,050 295,260 306,970
The compensation shown in Column (c) of the Summary
Compensation Table for the individuals named therein is covered
by the Retirement Plan and/or a SERP. Messrs. Gressette, Kenyon,
Timmerman, Young and Stedman now have credited service under the
Retirement Plan (or its equivalent under the SERP) of 31, 20, 15,
31 and 21 years, respectively.
The Company also has a Key Employee Retention Program (the "Key
Employee Retention Program") covering officers and certain other
executive employees that provides supplemental retirement and/or death
benefits for participants. Under the program, the Company will payeach participant may
elect to each participantreceive either a monthly retirement benefit for 180 months
upon retirement at or after age 65 a monthly retirement benefit equal to 25% of the average monthly
salary of the participant over his final 36 months of employment prior
to age 65, or an optional death benefit payable to a participant's
designated beneficiary monthly for 180 months, in an amount equal to
35% of the average monthly salary of the participant over his final 36
months of employment prior to age 65. In the event of the
participant's death prior to age 65, the Company will pay to the
participant's designated beneficiary for 180 months, a monthly benefit
equal to 50% of such participant's base monthly salary in effect at
death.
All of the executive officers named in the Summary Compensation
Table above are participating in the Key Employee
Retention Program.program. Estimated annual
retirement benefits payable at age 65 based on projected eligible
compensation (assuming increases of 4% per year) to the five executive
officers named in the Summary Compensation Table are as follows:
Mr. Gressette - $106,863;$113,790; Mr. Kenyon - $126,347;$122,658; Mr. Timmerman -
$105,411;$129,942; Mr. YoungBullwinkel - $56,013;$90,887; and Mr. StedmanSkolds - $66,729.
Life Insurance Plans
The Company offers its officers and certain other highly-
compensated employees an option to choose whole life insurance
(the "Whole Life Option") in lieu of the term life insurance
provided employees generally. Under this plan, the employee
becomes the owner of a policy with a death benefit of between
$200,000 and $550,000 depending upon the salary grade of the
employee.
70$93,234.
62
Termination, Severance and Change of Control ArrangementsTERMINATION, 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 obligatedobli-
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""gross-
up" payment) for any IRC Section 4999 excess tax or any such other
similar tax applicable to the severance payments. In addition, for 36
months after termination, the officer would receive coverage for
medical benefits and life insurance so as to provide the same level of
benefits previously enjoyed under group plans or individual policy
contracts or otherwise as determined by the Executive Committee of the
Board of Directors. Such benefits however would be reduced to the
extent that the participant receives similar benefits during the
period from another employer.
In addition to the Severance Plan, in the event of a merger,
consolidation or acquisition in which SCANA is not the surviving
corporation, target awards under the Performance Share Plan will
become immediately payable based on SCANA's shareholder return
performance as of the end of the most recently completed calendar year
for each performance period as to which the grant of target shares has
occurred at least six months previously.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There areDuring 1995, no executive officer-director interlocks where an
executiveofficer, employee or former officer of the
Company serves on the compensation
committee of another company that has an executive officer
serving on the Company's Board of Directors. Messrs. Hipp,
McMaster, Rhodes and Warren are all membersor its affiliates served as a member of the Long-Term
Compensation Committee which administersor the Performance Share
Plan. Messrs. Hipp and Rhodes also are membersCommittee, 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 which generally handles all otherduring 1995, he did not participate in any of
its deliberations concerning executive compensation matters. Mr. Warren was the Chief Executive Officer
ofofficer compensation.
Since January 1, 1995, the Company from April 23, 1986 until January 31, 1990.
Information with respect tohas engaged in business
transactions with entities with which Messrs. Hipp,Mr. Chapman (Chairman of both
the Performance Committee and the Long-Term Compensation Committee)
and Mr. McMaster Rhodes and Warren are connected are
described below. Mr. Gressette, Chairman of the Board and Chief
Executive Officer of the Company, is an ex-officio (i.e.
nonvoting)(a member of the Performance Committee.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 Performance
Committee receives his input on compensation matters concerning
executive compensation of other officers but the committee
deliberates and makes its decisions without his participation.
Mr. Rhodes is the Chairman and Chief Executive Officer of
Rhodes Oil Company, Inc. Purchases from Rhodes Oil Company, Inc.
totaling $62,500 for fuel oil and gasoline were madeamount paid during
19931995 by the Company.Company and its affiliates to NationsBank Corporation
affiliates on account of such transactions was $3,339,270. It is
anticipated that transactions such purchasesas described above will continue in
the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum
Company. Purchases from Winnsboro Petroleum Company totaling $77,549$71,413
for fuel oil and gasoline were made during 19931995 by the Company.Company and its
affiliates. It is anticipated that such purchases will continue in
the future.
71
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, is the President and Chief Executive Officer of The
Liberty Corporation. Mr. Hipp and John A. Warren are
Directors of The Liberty Corporation. During 1993 certainCorporation, served as a member of the insurance policies purchased by the Company on the livesCompany's Long-Term
Compensation Committee.
63
Compensation of employeesDirectors
Fees. During 1995, directors who were written by Liberty Life Insurance Company, a
subsidiary of the Liberty Corporation, and it is expected that
this relationship will continue in the future. The total amount
paid during 1993 by the Company to Liberty Life Insurance Company
was $538,905.
COMPENSATION OF DIRECTORS
Fees
All of the Directorsnot employees of the
Company are also Directors of
SCANA. During 1993, directors who are not employees of SCANA or
its subsidiaries were each paid $14,500$16,000 annually for services rendered, plus $1,500$1,800
for each Board meeting attended and $700$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
$150.$200. The fee for attendance at a conference is $500.$850. In addition,
Directorsdirectors are paid, as part of their compensation, travel, lodging and
incidental expenses related to attendance at meetings and conferences.
Directors who are employees of SCANAthe Company or its subsidiariesaffiliates receive
no compensation for serving as directors or attending meetings.
Deferral Plan
The CompanyPlan. 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 19931995 and currently, the rate is
set at the announced prime rate of TheWachovia Bank of South Carolina
National Bank. During 1993,Carolina.
Mr. Cassels and Mr. Rhodes were the only directordirectors participating in
the plan wasduring 1995. Mr. Rhodes. InterestCassels became a participant in January
1994 and Mr. Rhodes in July 1987, and interest credited to Mr. Rhodes'their
deferral accountaccounts during 19931995 was $8,526.$3,591.94 and $19,557.86,
respectively.
Endowment PlanPlan. Each director participates in the Directors'
Endowment Plan, which provides for the Company tothat 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 andSCANA; any out-of-stateout-of-
state designation must be approved by the Performance Committee. The
designated institutions are reviewed on an annual basis by the Chief
Executive Officer to assure compliance with the intent of the program.
The plan is intended to reinforce SCANA's commitment to quality higher
education and is intended to enhance SCANA's ability to attract and
retain qualified board members.
72
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
All shares of the Company's Common Stock are held, beneficially
and of record, by SCANA Corporation.
The table set forth below indicates as of March 10, 1994,
the shares of SCANA's Common
Stock beneficially owned as of March 8, 1996 by each
continuing director and
nominee, each of the executive officers named in the Summary
Compensation Table on page 66,59, 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)1 Owner of Ownership (1)1
B. L. Amick 1,2432,486 W. H.Hayne Hipp 1,4002,800
W. B. Bookhart, Jr. 6,88415,761 B. D. Kenyon 4,78218,883
G. J. Bullwinkel 17,255 F. C. McMaster 5,630
W. T. Cassels, Jr. 1,000 F. C. McMaster 10,2882,000 Henry Ponder 12,381
H. M. Chapman 3,127 Henry Ponder 4,8066,000 J. B. Rhodes 7,780
J. B. Edwards 2,2174,665 J. B. Rhodes 3,434L. Skolds 6,414
E. T. Freeman 1,5004,220 W. B. Timmerman 12,88936,459
L. M. Gressette, Jr. 14,64947,493 E. C. Wall, Jr. 7,00014,000
B. A. Hagood 1,140 John A. Warren 50,823
J. H. Young 5,108
R. W. Stedman 6,4742,370
All directors and executive officers as a group (18(21 persons) TOTAL 138,764247,243
TOTAL PERCENT OF CLASS 0.3%
(1)0.2%
The information set forth above as to the security ownership has
been furnished to the Company by such persons.
_____________________
1 Includes shares owned by close relatives, the beneficial
ownership
of which is disclaimed by the director or nominee, as follows:
Mr. Amick - 240;480; Mr. Bookhart - 1,913; Mr. Chapman - 127;4,498; Mr. Gressette - 530;1,060;
Mr. Hagood - 159;334; Mr. McMaster - 6,365;
Mr. Warren - 7,160.2,000.
Includes shares purchased through December 31, 1993,1995, but not
thereafter, by the Trustee under the Savings Plan.
The information set forth above as to the security ownership
has been furnished to the Company by such persons.64
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related
transactions, see Item 11.,11, "Compensation Committee Interlocks and
Insider Participation."
73
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
Financial Statements and Schedules
See Index to Consolidated Financial Statements and
Supplementary Data on page 28.30.
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
The Company filed a report on Form 8-K on January 13, 1994
in response to Item 5, "Other Events" regarding the settlement
with Westinghouse Electric Corporation of a lawsuit relating to
the steam generators provided to the Company's Summer Station.
74None
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 15, 199420, 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,
and Chief Executive Officer and Director
DATE February 15, 199420, 1996
(ii) Principal financial officer:
BY (SIGNATURE) s/W.K. B. TimmermanMarsh
(NAME AND TITLE) W.K. B. Timmerman,Marsh, Chief Financial Officer
DATE February 15, 199420, 1996
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and Controller
DATE February 15, 199420, 1996
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 15, 1994
7520, 1996
66
BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 15, 199420, 1996
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 15, 199420, 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 15, 199420, 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, BY (SIGNATURE) s/JohnFile 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. Warren
(NAME AND TITLE) JohnIndenture 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. Warren, Director
DATE February 15, 1994
76Copy 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