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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission File Number 1-8809
SCANA CORPORATION
(Exact name of registrant as specified in its charter)
SOUTH CAROLINA 57-0784499
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)
1426 MAIN STREET, COLUMBIA, SOUTH CAROLINA 29201
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (803) 748-3000
Securities registered pursuant to 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock, without par value New York Stock Exchange
Securities registered pursuant to 12(g) of the Act:
None
(Title of class)
Indicate by check mark whether the registrant: (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes x No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
State the aggregate market value of the voting stock held by
non-affiliates of the registrant. The aggregate market value shall
be computed by reference to the price at which the stock was sold,
or the average bid and asked prices of such stock, as of a
specified date within 60 days prior to the date of filing. (See
definition of affiliate in Rule 405.)
Note: If a determination as to whether a particular person
or entity is an affiliate cannot be made without involving
unreasonable effort and expense, the aggregate market value of the
common stock held by non-affiliates may be calculated on the basis
of assumptions reasonable under the circumstances, provided that
the assumptions are set forth in this form.
The aggregate market value of the voting stock held by
nonaffiliates of the registrant was $2,132,604,581 at February 28,
1995 based on the closing price of the Common Stock on such date,
as reported by the New York Stock Exchange composite tape in The
Wall Street Journal.
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.
The total number of shares of the registrant's Common
Stock, no par value, outstanding at February 28, 1995 was
48,330,982.
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).
(1) Specified sections of the Registrant's 1995 Proxy
Statement,
dated March 17, 1995, in connection with its 1995 Annual
Meeting of Stockholders, are incorporated by reference in
Part III hereof.
2
TABLE OF CONTENTS
Page
DEFINITIONS ....................................................... 4
PART I
Item 1. Business ............................................ 5
Item 2. Properties .......................................... 21
Item 3. Legal Proceedings ................................... 23
Item 4. Submission of Matters to a Vote of
Security Holders ................................... 23
Corporate Structure .......................................... 24
Executive Officers of the Registrant ......................... 25
PART II
Item 5. Market for Registrant's Common Stock
and Related Security Holder Matters ................ 26
Item 6. Selected Financial Data ............................. 27
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ...... 29
Item 8. Financial Statements and Supplementary Data ......... 38
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ............. 66
PART III
Item 10. Directors and Executive Officers of the
Registrant ......................................... 66
Item 11. Executive Compensation .............................. 66
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 66
Item 13. Certain Relationships and Related Transactions ...... 66
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 67
SIGNATURES ........................................................ 68
3
DEFINITIONS
The following abbreviations used in the text have the meaning set forth below
unless the context requires otherwise:
ABBREVIATION TERM
AFC......................... Allowance for Funds Used During Construction
BTU......................... British Thermal Unit
Circuit Court............... South Carolina Circuit Court
Clean Air Act............... Clean Air Act Amendments of 1990
Company..................... SCANA Corporation and its subsidiaries
Consumer Advocate........... Consumer Advocate of South Carolina
Dekatherm................... One million BTUs
DHEC........................ South Carolina Department of Health and
Environmental Control
DOE......................... United States Department of Energy
DRP......................... SCANA Corporation Dividend Reinvestment and Stock
Purchase Plan
EPA......................... United States Environmental Protection Agency
FERC........................ United States Federal Energy Regulatory
Commission
Fuel Company................ South Carolina Fuel Company, Inc.
GENCO....................... South Carolina Generating Company, Inc.
Hydrocarbons................ SCANA Hydrocarbons, Inc.
KVA......................... Kilovolt-ampere
KW.......................... Kilowatt
KWH......................... Kilowatt-hour
LNG......................... Liquefied Natural Gas
MCF......................... Thousand Cubic Feet
MW.......................... Megawatt
NEPA........................ National Energy Policy Act of 1992
NRC......................... United States Nuclear Regulatory Commission
Peoples..................... Peoples Natural Gas Company of South Carolina
Petroleum Resources......... SCANA Petroleum Resources, Inc.
Pipeline Corporation........ South Carolina Pipeline Corporation
PSA......................... The South Carolina Public Service Authority
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935
SCANA....................... SCANA Corporation, the parent company
SCE&G....................... South Carolina Electric & Gas Company
SEC......................... United States Securities and Exchange
Commission
Southern Natural............ Southern Natural Gas Company
SPSP........................ SCANA Corporation Stock Purchase-Savings Plan
Suburban.................... Suburban Propane Group, Inc.
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipeline Corporation
USEC........................ United States Enrichment Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams coal-fired, electric generating
station owned by GENCO
4
PART I
ITEM 1. BUSINESS
THE COMPANY
ORGANIZATION
SCANA, a South Carolina corporation having general
business powers, was incorporated on October 10, 1984 and is a
public utility holding company within the meaning of PUHCA but is
exempt from registration under such Act (see Regulation). SCANA
has its principal executive office at 1426 Main Street, Columbia,
South Carolina 29201, telephone number (803) 748-3000. SCANA holds
all the capital stock of each of its subsidiaries except for the
Preferred Stock of SCE&G and the capital stock of SCANA's indirect,
wholly owned subsidiaries which are not material individually or in
the aggregate. SCANA and its subsidiaries had 4,575 full-time,
permanent employees as of December 31, 1994 as compared to 4,788
full-time, permanent employees as of December 31, 1993.
SEGMENTS OF BUSINESS
SCANA neither owns nor operates any physical properties. It
currently has 12 direct, wholly owned subsidiaries which are
engaged in the functionally distinct operations described below.
Regulated Utilities
The Company's principal subsidiary, SCE&G, 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. SCE&G also
renders urban bus service in the metropolitan areas of Columbia and
Charleston, South Carolina. SCE&G's business is subject to
seasonal fluctuations. Generally, sales of electricity are higher
during the summer and winter months because of air-conditioning and
heating requirements, and sales of natural gas are greater in the
winter months due to its use for heating requirements.
SCE&G's electric service area extends into 24 counties
covering more than 15,000 square miles in the central, southern and
southwestern portions of South Carolina. The service area for
natural gas encompasses all or part of 29 of the 46 counties in
South Carolina and covers more than 20,000 square miles. The total
population of counties representing the combined service area is
approximately 2.3 million.
The predominant industries in the territories served by SCE&G
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.
GENCO owns and operates Williams Station and sells electricity
solely to SCE&G. Fuel Company acquires, owns and provides
financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide
emission allowance requirements.
Pipeline Corporation is engaged in the purchase, transmission
and sale of natural gas on a wholesale basis to distribution
companies and directly to industrial customers in 39 counties
throughout South Carolina. Pipeline Corporation owns LNG
liquefaction and storage facilities. It also supplies the natural
gas for SCE&G's gas distribution system. Other resale customers
include municipalities and county gas authorities and gas
utilities. The industrial customers of Pipeline Corporation are
primarily engaged in the manufacturing or processing of ceramics,
paper, metal, food and textiles.
5
Nonregulated Businesses
Petroleum Resources owns and/or operates oil and gas
properties in 12 states and Federal waters offshore Texas,
Louisiana and Alabama.
Hydrocarbons markets natural gas and light hydrocarbons. It
also owns and operates an 80 million gallon underground propane
storage cavern near York, South Carolina and a 62 mile, six-inch
propane pipeline that connects the cavern facility with Dixie
Pipeline Company near Bethune, South Carolina. The cavern leases
storage space to industries, utilities and propane suppliers.
Hydrocarbons also owns and operates the Wilburton Gathering System
in Oklahoma.
Suburban Propane purchases, delivers and sells propane. In
1994 Suburban sold approximately 23 million gallons of propane and
had approximately 32,000 residential, commercial and industrial
customers at year end.
MPX Systems, Inc. is involved in telecommunications-related
ventures providing fiber optic telecommunications, video
conferencing and specialized mobile radio services. Having
installed over 2,000 miles of fiber optic cable in South Carolina,
Georgia, Alabama, Mississippi, Louisiana and Texas, MPX has, in
addition, recently begun efforts in video conferencing and the
establishment of a Specialized Mobile Radio system in South
Carolina and is also pursuing Personal Communication Services
licenses for wireless communications in the Southeast.
In January 1994 the Company signed an agreement to sell
substantially all of the real estate assets of SCANA Development
Corporation to Liberty Properties Group, Inc. of Greenville, South
Carolina for $91.5 million. On March 4, 1994 the Company and
Liberty amended the agreement to exclude certain projects then
under construction, and the sales price was reduced to $49.6
million. The transaction was closed on May 27, 1994. Certain
other assets of SCANA Development Corporation are being sold to
other parties. These transactions did not have a material impact
on the Company's financial position or results of operations.
ServiceCare, Inc. is engaged in providing energy related
products and services beyond the energy meter. Its primary
business is providing homeowners with service contracts on their
home appliances. At year end, ServiceCare had approximately 16,000
customers.
Primesouth, Inc. is engaged in power plant management and
maintenance services.
SCANA Capital Resources, Inc. has provided equity capital for
diversified investments.
Information with respect to major segments of business for the
years ended December 31, 1994, 1993 and 1992 is contained in Note
11 of the Notes to Consolidated Financial Statements and all such
information is incorporated herein by reference.
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulatory
protection. The transition began with the enactment of the Public
Utility Regulatory Policies Act of 1978 which facilitated the entry
of competitors into the electric generation business.
Subsequently, NEPA was enacted in 1992 to promote competition among
utility and nonutility generators in the wholesale electric
generation market. Recent initiatives in some states to lessen
regulation and promote competition, particularly with regard to
retail transmission access, also have accelerated the utility
industry's transition.
Future deregulation of electric wholesale and retail markets
will create opportunities to compete for new and existing customers
and markets. As a result, profit margins and asset values of some
utilities could be adversely affected.
6
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, SCE&G, reorganized
its operations around Strategic Business Units. Maintaining a
competitive cost structure is of paramount importance in the
utility's strategic plan. SCE&G has undertaken a variety of
initiatives, including reductions in operation and maintenance
costs and in staffing levels. SCE&G 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.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The cash requirements of the Company arise primarily from
SCE&G's operational needs, the Company's construction program and
the need to fund the activities or investments of the Company's
nonregulated subsidiaries. The ability of the Company's regulated
subsidiaries to replace existing plant investment, as well as to
expand to meet future demand for electricity and gas, will depend
upon their ability to attract the necessary financial capital on
reasonable terms. The Company's regulated subsidiaries recover 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 regulated
subsidiaries expand their construction programs, 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
the regulated subsidiaries' ability to obtain adequate and timely
rate relief.
As discussed in Note 2B of Notes to Consolidated Financial
Statements, on June 7, 1993 the PSC issued an order granting SCE&G
a 7.4% annual increase in retail electric rates which was
implemented in two phases over a two year period: phase one,
effective June 1993, producing $42.0 million annually, and phase
two, effective June 1994, producing $18.5 million annually, based
on a test year.
During 1995 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 42%, excluding dividends), sales of additional
shares of common stock including sales pursuant to the DRP and
SPSP, and the issuance and sale of debt securities. Short-term
liquidity is expected to be provided primarily by issuance of
commercial paper. The timing and amount of such sales and the type
of securities to be sold will depend upon market conditions and
other factors.
The Company's estimates of its cash requirements for
construction (excluding potential oil and gas investments) and
nuclear fuel expenditures, which are subject to continuing review
and adjustment, for 1995 and the four-year period 1996-1999 as now
scheduled, are as follows:
Type of Facilities 1996-1999 1995
(Thousands of Dollars)
South Carolina Electric & Gas Company:
Electric Plant:
Generation . . . . . . . . . . . . . . $ 388,193 $129,825
Transmission . . . . . . . . . . . . . 92,701 25,928
Distribution . . . . . . . . . . . . . 295,571 67,283
Other. . . . . . . . . . . . . . . . . 69,322 16,874
Nuclear Fuel. . . . . . . . . . . . . . . 68,171 23,084
Gas . . . . . . . . . . . . . . . . . . . 60,415 18,895
Transit . . . . . . . . . . . . . . . . . 1,012 432
Common . . . . . . . . . . . . . . . . . 35,090 25,342
Nonutility . . . . . . . . . . . . . . . 580 175
Total . . . . . . . . . . . . . . . . . 1,011,055 307,838
Other Companies Combined. . . . . . . . . . 214,960 63,530
Total . . . . . . . . . . . $1,226,015 $371,368
The above estimates exclude AFC.
7
Construction
The Company's cost estimates for its construction program for
the periods 1995 and 1996-1999, shown in the above table, include
costs of the projects described below.
SCE&G entered into a contract with Duke/Fluor Daniel in 1991
to design, engineer and build a 385 MW coal-fired electric
generating plant near Cope, South Carolina in Orangeburg County.
Construction of the plant began in November 1992 and is expected to
be complete in late 1995 with commercial operation beginning in
early 1996. The estimated cost of the Cope plant, excluding
financing costs and allowance for funds used during construction
(AFC) but including an allowance for escalation, is $450 million.
In addition, the transmission lines for interconnection with
SCE&G's system are expected to cost $26 million. Until completion
of the new plant, SCE&G is contracting for additional power as
necessary to ensure that the energy demands of its customers can be
met.
The steam generators at Summer Station were replaced in late
1994 during the regularly scheduled refueling outage. The
replacement was completed in 38 days, a new U.S. record and only
one day off the world record for a steam generator replacement.
The new steam generators are expected to result in shorter, less
costly refueling outages, and greater electricity output is
expected to result from less required maintenance.
During 1994 SCE&G and GENCO expended approximately $11.4
million as part of a program to extend the operating lives of
certain generating facilities. Additional improvements to be made
under the program during 1995 are estimated to cost approximately
$15.0 million.
Additional Capital Requirements
In addition to the Company's capital requirements for 1995
described above, approximately $25.6 million will be required for
refunding and retiring outstanding securities and obligations. For
the years 1996-1999, the Company has an aggregate of $338.3 million
of long-term debt maturing (including approximately $59.4 million
for sinking fund requirements, of which $59.0 million may be
satisfied by deposit and cancellation of bonds issued upon the
basis of property additions or bond retirement credits) and $9.8
million of purchase or sinking fund requirements for preferred
stock.
Actual 1995 expenditures may vary from the estimates set forth
above due to factors such as inflation, economic conditions,
regulation, legislation, rates of load growth, environmental
protection standards and the cost and availability of capital.
Financing Program
The Company has in effect a medium-term note program for the
issuance from time to time of unsecured medium-term debt
securities. The proceeds from the sales of these securities may be
used to fund additional business activities in nonutility subsidi-
aries, to reduce short-term debt incurred in connection therewith
or for general corporate purposes. In December 1994, a shelf
registration statement filed with the Securities and Exchange
Commission became effective, providing for the issuance of up to an
additional $250 million in medium-term notes. At December 31, 1994
the Company had available for issuance $317.6 million under this
program.
SCE&G's First and Refunding Mortgage Bond Indenture, dated
April 1, 1945 (Old Mortgage), contains provisions prohibiting the
issuance of additional bonds thereunder (Class A Bonds) unless net
earnings (as therein defined) for 12 consecutive months out of the
15 months prior to the month of issuance are at least twice the
annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1994 the
Bond Ratio was 3.52. The issuance of additional Class A Bonds is
restricted also to an additional principal amount equal to 60% of
unfunded net property additions (which unfunded net property
additions totaled approximately $499.8 million at December 31,
1994), Class A Bonds issued on the basis of retirements of Class A
Bonds (no retirement credits remained at December 31, 1994) and
Class A Bonds issued on the basis of cash on deposit with the
Trustee.
8
SCE&G has placed a new bond indenture (New Mortgage) dated
April 1, 1993 on substantially all of its electric properties under
which its future mortgage-backed debt (New Bonds) will be issued.
New Bonds are expected to be issued under the New Mortgage on the
basis of a like principal amount of Class A Bonds issued under the
Old Mortgage, which have been deposited with the Trustee of
the New Mortgage (of which $57 million were available for such
purpose at December 31, 1994), until such time as all presently
outstanding Class A Bonds are retired. Thereafter, New Bonds will
be issuable on the basis of property additions in a principal
amount equal to 70% of the original cost of electric and common
plant properties (compared to 60% of value for Class A Bonds under
the Old Mortgage), cash deposited with the Trustee, and retirement
of New Bonds. New Bonds will be issuable under the New Mortgage
only if adjusted net earnings (as therein defined) for 12
consecutive months out of the 18 months immediately preceding the
month of issuance are at least twice the annual interest
requirements on all outstanding bonds (including Class A Bonds) and
New Bonds to be outstanding (New Bond Ratio). For the year ended
December 31, 1994 the New Bond Ratio was 4.85.
The following additional financing transactions have occurred
since December 31, 1993:
, On January 14, 1994 the Company closed unsecured bank
loans totaling $60 million, due January 13, 1995, and used
the proceeds to pay off a loan in a like total amount. In
January 1995 the Company refinanced the loans with an
unsecured bank loan of $60 million due January 12, 1996 at an
initial interest rate of 6.44%, subject to reset quarterly at
LIBOR plus ten basis points.
, On July 21, 1994 SCE&G issued $100 million of First
Mortgage Bonds, 7.70% series due July 15, 2004 to
repay short-term borrowings in a like amount.
, On November 3, 1994 SCE&G issued $30 million of Pollution
Control Facilities Revenue Bonds due November 1, 2024. The
proceeds from the sale of the bonds are being used to defray
the cost of constructing certain facilities for the disposal
of solid waste at SCE&G's Cope Generating Station under
construction in Orangeburg County, South Carolina.
Without the consent of at least a majority of the total voting
power of SCE&G's preferred stock, SCE&G 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 SCE&G'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, SCE&G and
GENCO must obtain FERC authority to issue short-term debt. The
FERC has authorized SCE&G to issue up to $200 million of unsecured
promissory notes or commercial paper with maturity dates of
12 months or less but not later than December 31, 1997. GENCO has
not sought such authorization.
The Company had $479.1 million authorized lines of credit and
had unused lines of credit of $455.1 million at December 31, 1994.
In addition SCE&G has a credit agreement for a maximum of $75
million to finance nuclear and fossil fuel inventories with $24.4
million available at December 31, 1994.
SCE&G's Restated Articles of Incorporation prohibit issuance
of additional shares of preferred stock without consent of the
preferred stockholders unless net earnings (as defined therein) for
the 12 consecutive months immediately preceding the month of
issuance are at least one and one-half times the aggregate of all
interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1994
the Preferred Stock Ratio was 2.29.
On December 16, 1994 the Company registered with the SEC
2,000,000 additional shares of the Company's common stock to be
issued and sold under the SPSP.
During 1994 the Company issued 595,438 shares of the Company's
common stock under the DRP. In addition, the Company issued 781,354
shares of its common stock pursuant to its SPSP. The Company has
authorized and reserved for issuance, and registered under
effective registration statements, 1,470,386 and 2,091,066 shares
of common stock pursuant to the DRP and the SPSP, respectively.
9
In January 1994 the Company signed an agreement to sell
substantially all of the real estate assets of SCANA Development
Corporation to Liberty Properties Group, Inc. of Greenville, South
Carolina for $91.5 million. On March 4, 1994 the Company and
Liberty amended the agreement to exclude certain projects then
under construction, and the sales price was reduced to $49.6
million. The transaction was closed on May 27, 1994. Certain
other assets of SCANA Development Corporation are being sold to
other parties. These transactions did not have a material impact
on the Company's financial position or results of operations.
MPX Systems Inc., a wholly owned subsidiary of SCANA, through
a joint venture with ITC Transmission Systems, a Georgia-based
telecommunications holding company, is constructing a fiber optic
network through Texas, Louisiana, Mississippi, Alabama and Georgia.
The network, which will consist of more than 900 miles of fiber
optic lines, is expected to be completed by June 1995 at a cost of
$58 million. In addition, MPX is pursuing Personal Communication
Services licenses for wireless communications in the Southeast
through a joint venture with ITC Personal Communications, Inc.,
Intercel PCS Services, Inc., and South Atlantic PCS Corporation.
A $40 million construction loan obtained by the joint venture has
been guaranteed in part by SCANA Corporation. All new ventures
currently capitalize on fiber infrastructure in place and provide
for expansion of the network.
The ratio of earnings to fixed charges (SEC method) was 3.02,
3.41, 2.79, 3.24 and 4.07 for the years ended December 31, 1994,
1993, 1992, 1991 and 1990 respectively.
The Company expects that it has or can obtain adequate sources
of financing to meet its projected cash requirements.
Fuel Financing Agreements
SCE&G has assigned to Fuel Company all of its rights and
interests in its various contracts relating to the acquisition and
ownership of nuclear and fossil fuel. To finance nuclear and
fossil fuel, Fuel Company issues, from time to time, its promissory
notes with maturities of less than 270 days ("Commercial Paper").
The issuance of Commercial Paper is supported by an irrevocable
revolving credit agreement which expires July 31, 1996.
Accordingly, the amounts outstanding have been included in long-
term debt. Fuel Company's Commercial Paper and amounts outstanding
under the revolving credit agreement, if any, are guaranteed by
SCE&G. The credit agreement provides for a maximum amount of $75
million that may be outstanding at any time.
At December 31, 1994 Commercial Paper outstanding for
nuclear and fossil fuel inventories was approximately $50.6
million at a weighted average interest rate of 6.06%. Such fuel
inventories and fuel-related assets and liabilities are included in
the Company's financial statements (See Note 4 of Notes to
Consolidated Financial Statements).
ELECTRIC OPERATIONS
Electric Sales
In 1994 residential sales of electricity accounted for 42% of
electric sales revenues; commercial sales 30%; industrial sales
21%; sales for resale 4%; and all other 3%. KWH sales by
classification for the years ended December 31, 1994 and 1993 are
presented below:
Sales
KWH %
Classification 1994 1993 Change
(thousands)
Residential 5,311,139 5,650,753 (6.01)
Commercial 4,846,619 4,835,492 0.23
Industrial 5,161,717 4,887,121 5.62
Sale for resale 1,024,376 1,005,968 1.83
Other 494,030 500,937 (1.38)
Total Territorial 16,837,881 16,880,271 (0.25)
Interchange 171,046 198,059 (13.64)
Total 17,008,927 17,078,330 (0.41)
10
SCE&G furnishes electricity for resale to three
municipalities, three investor-owned utilities, two electric
cooperatives and one public power authority. Such sales for resale
accounted for 4% of SCE&G's total electric sales revenues in 1994.
During 1994 the Company recorded a net increase of 7,538
electric customers, increasing its total customers to 476,412.
The electric sales volume decreased for the year ended
December 31, 1994 compared to the corresponding period as a result
of decreased residential kilowatt-hour sales and interchange power
delivered due to milder weather in 1994. The peak demand of 3,444
MW was recorded on January 19, 1994. The all-time record of 3,557
MW was set on July 29, 1993.
Electric Interconnections
SCE&G's transmission system is part of the interconnected grid
extending over a large part of the southern and eastern portion of
the nation. SCE&G, Virginia Power Company, Duke Power Company,
Carolina Power & Light Company, Yadkin, Incorporated and PSA are
members of the Virginia-Carolinas Reliability Group, one of the
several geographic divisions within the Southeastern Electric
Reliability Council which provides for coordinated planning for
reliability among bulk power systems in the Southeast. SCE&G 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 for the years 1992-1994.
1994 1993 1992
Nuclear:
Per million BTU $ .51 $ .47 $ .52
Coal:
Per ton $40.43 $40.48 $40.45
Per million BTU 1.59 1.57 1.57
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.39 $ 1.32 $ 1.27
The fuel costs shown above exclude the effects of a PSC
approved offsetting of fuel costs through the application of
credits carried on SCE&G's books as a result of a 1980 settlement
of certain litigation.
Fuel Supply
The following table shows the sources and approximate
percentages of total KWH generation by each category of fuel for
the years 1992-1994 and the estimates for 1995 and 1996.
Percent of Total KWH Generated
Actual Estimated
1994 1993 1992 1996 1995
Coal 77% 72% 65% 72% 69%
Nuclear 17 22 29 23 26
Hydro 6 5 5 5 5
Natural Gas & Oil - 1 1 - -
100% 100% 100% 100% 100%
Coal is currently used at all four of SCE&G's major fossil
fuel-fired plants and GENCO's Williams Station. Unit train
deliveries are used at all of these plants. On December 31, 1994
SCE&G had approximately a 74-day supply of coal in inventory and
GENCO had approximately a 68-day supply.
11
The supply of coal is obtained through contracts and purchases
on the spot market. Spot market purchases are expected to continue
for coal requirements in excess of those provided by the Company's
existing contracts. Contracts for the purchase of coal represent
the following percentages of estimated requirements for 1995
(approximately 5.1 million tons) and expire at the dates indicated
(giving effect to the Company's potential to exercise renewal
options):
Range of % of Initial Final
No. of Tons % of 1995 Sulfur Content Expiration Expiration
Per Year Requirement per Contract Date (1) Date (1)
482,500 9.5 1.1-1.5 02/28/1996 02/29/2000
359,500 7.0 1.0-1.8 12/31/1996 12/31/2002
562,500 11.0 1.1-2.0 03/31/1997 03/31/2003
144,000 2.8 1.0-1.6 04/30/1995 04/30/1997
981,000 19.2 up to 1.5 12/31/1996 12/31/2002
732,170 14.4 0.75-1.75 04/30/1997 04/30/2003
425,000 8.3 0.8-1.5 06/30/1995 06/30/1999
3,686,670 72.2
(1) Contract extensions beyond the initial expiration date are
subject to mutual agreement on price, terms, quantity and
quality.
All of the above contracts, except the contracts expiring on
April 30, 1995 and June 30, 1995 which have firm prices, are
subject to periodic price adjustments based on changes in indices
published by the U. S. Department of Labor.
Coal purchased in December 1994 had an average sulfur content
of 1.26%, which permitted SCE&G and GENCO to comply with existing
environmental regulations. The Company believes that SCE&G's and
GENCO's operations are in substantial compliance with all existing
regulations relating to the discharge of sulfur dioxide. The
Company has not been advised by officials of DHEC that any more
stringent sulfur content requirements for existing plants are
contemplated at the State level. However, the Company will be
required to meet the more stringent Federal emissions standards
established by the Clean Air Act (see "Environmental Control
Matters").
SCE&G currently has adequate supplies of uranium under
contract to manufacture nuclear fuel for Summer Station through
1997. The following table summarizes all contract commitments for
the stages of nuclear fuel assemblies:
Commitment Contractor Regions(1) Term
Uranium Energy Resources
of Australia 9-13 1990-1996
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995
Enrichment USEC (2) Through 2022
Fabrication Westinghouse 1-21 1982-2009
Reprocessing None
(1) A region represents approximately one-third to one-half of
the nuclear core in the reactor at any one time. Region no.
11 was loaded in 1994 and Region no. 12 will be loaded in
1996.
(2) The contract with the USEC is a "requirements" type contract
whereby the USEC supplies total enrichment requirements for
the unit through the year 2022, as specified by its then
current schedule.
SCE&G has on-site spent fuel storage capability until at least
2008 and expects to be able to expand its storage capacity to
accommodate the spent fuel output for the life of the plant through
rod consolidation, dry cask storage or other technology as it
becomes available. In addition, there is sufficient on-site
storage capacity over the life of Summer Station to permit storage
of the entire reactor core in the event that complete unloading
should become desirable or necessary for any reason. (See "Nuclear
Fuel Disposal" under "Environmental Control Matters" for
information regarding the contract with the DOE for disposal of
spent fuel.)
12
GAS OPERATIONS
Gas Sales
In 1994 residential sales accounted for 29% of gas sales
revenues; commercial sales 19%; industrial sales 38%; sales for
resale 14%. Dekatherm sales by classification for the years ended
December 31, 1994 and 1993 are presented below:
SALES
DEKATHERMS %
CLASSIFICATION 1994 1993 CHANGE
Residential 11,531,558 12,651,000 (8.9)
Commercial 9,886,622 9,611,556 (0.3)
Industrial 41,513,880 30,335,059 36.9
Sale for resale 15,178,820 19,144,130 (20.7)
Transportation gas 16,067,294 29,542,805 (45.6)
Total 94,178,174 101,284,550 (7.3)
During 1994 the Company recorded a net increase of 3,878
customers, increasing its total customers to 238,614.
The demand for gas is affected by conservation, the weather,
the price relationship between gas and alternate fuels and other
factors.
The deregulation of natural gas prices at the wellhead which
took place on January 1, 1985 and the changes in the prices of
natural gas that have occurred under Federal regulation have
resulted in the development of a spot market for natural gas in the
producing areas of the country. Pipeline Corporation has been
successful in purchasing lower cost natural gas in the spot market
and arranging for its transportation to South Carolina. Pipeline
Corporation has also negotiated contracts with certain direct and
indirect industrial customers for the transportation of natural gas
that the industrial customers purchase directly from suppliers.
On November 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which deregulated the markets for interstate sales of
natural gas by requiring that pipelines provide transportation
services that are equal in quality for all gas supplies whether the
customer purchases gas from the pipeline or another supplier. The
Company's gas subsidiaries are positioned for the related market
changes arising from this order.
Pipeline Corporation, operating wholly within the State of
South Carolina, provides natural gas utility service, including
transportation services, for its customers, and supplies natural
gas to SCE&G and other wholesale purchasers. Hydrocarbons acquires
and sells natural gas in the newly deregulated markets. Petroleum
Resources owns natural gas reserves that supply natural gas for the
interstate markets. Neither Hydrocarbons nor Petroleum Resources
supplies natural gas to any affiliate for use in providing
regulated gas utility services.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for alternate fuel vehicles for Federal, state,
municipal and private fleets which increase over a period of years.
The Company expects these requirements for alternate fuel vehicles
to develop business opportunities for the sale of compressed
natural gas as fuel for vehicles, but it cannot predict the
magnitude of this new market.
13
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts
with producers and marketers on a short-term basis at current price
indices and on a long-term basis for reliability assurance at index
prices plus a gas inventory charge. The gas is brought to South
Carolina through transportation agreements with both Southern
Natural and Transco. The volume of gas which Pipeline Corporation
is entitled to transport through these contracts on a firm basis is
shown below:
Maximum Daily
Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 188,000
Transco Firm Transportation 29,300
Total 217,300
Additional natural gas volumes are brought to Pipeline
Corporation's system as capacity is available for interruptible
transportation.
During 1994 the average cost per MCF of natural gas purchased
for resale, including spot market purchases, was approximately
$2.00 compared to approximately $2.42 during 1993.
To meet the requirements of its other high priority natural
gas customers during periods of maximum demand, Pipeline
Corporation supplements its supplies of natural gas from two LNG
plants. The LNG plants are capable of storing the liquefied
equivalent of 1,900,000 MCF of natural gas, of which approximately
1,524,833 MCF were in storage at December 31, 1994. On peak days
the LNG plants can regasify up to 150,000 MCF per day.
Additionally, Pipeline Corporation had contracted for 6,450,727
MCF of natural gas storage space on December 31, 1994, of which
4,550,847 MCF were in storage at such date.
The Company believes that current supplies under contract and
spot market purchases of natural gas are adequate to meet existing
customer demands for service and to accommodate growth.
Curtailment Plans
The FERC has established allocation priorities applicable to
firm and interruptible capacities on interstate pipeline companies
which require Southern Natural and Transco to allocate capacity to
Pipeline Corporation. The FERC allocation priorities are not
applicable to deliveries by Pipeline Corporation to its customers,
which are governed by a separate curtailment plan approved by the
PSC.
Gas Reserves
Petroleum Resources is actively involved in oil and natural
gas exploration, development and production activities. It
currently owns and/or operates oil and gas properties in Texas,
Louisiana, Mississippi, Oklahoma, California, Arkansas, Nebraska,
Kansas, New Mexico, Alabama, Utah, Wyoming and Federal waters
offshore Texas, Louisiana and Alabama.
Gas Marketing
Hydrocarbons markets natural gas as well as other light
hydrocarbons. Hydrocarbons also owns and operates the Wilburton
Gathering System in Oklahoma.
Propane Operations
Suburban purchases, delivers and sells propane. In 1994
Suburban sold approximately 23 million gallons of propane and had
approximately 32,000 residential, commercial and industrial
customers at year end.
Hydrocarbons owns and operates an 80 million gallon under-
ground propane storage facility that leases storage space to
industrial companies, utilities and others. It also owns and
operates a 62 mile propane pipeline connected to the Dixie Pipeline
System which traverses central South Carolina.
14
REGULATION
General
SCANA is a public utility holding company within the meaning
of PUHCA, but is exempt under Section 3(a)(1) of PUHCA from
regulation by the SEC as a registered holding company unless and
until the SEC shall otherwise order, except for Section 9(a)(2)
thereof prohibiting the acquisition of securities of other public
utilities without a prior order of the SEC.
SCE&G 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.
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 any electric utility that owns
transmission facilities used for wholesale sales of electric energy
to provide transmission service (including any enlargement of
transmission capacity needed to provide the service) to the
applicant. Charges for transmission service must be "just and
reasonable" and a utility is entitled to recover "all legitimate,
verifiable economic costs" incurred in connection with any
transmission service so ordered. The FERC may not order such
service where it (1) would "unreasonably impair the continued
reliability of electric wheeling" judged by reference to
"consistently applied regional or national reliability standards,
guidelines or criteria;" (2) would result in "retail wheeling;" or
(3) would conflict with state laws governing retail marketing areas
of electric utilities. Electric utilities, including exempt and
non-exempt holding companies, may own and operate EWGs subject to
advance approval by state utility commissions, which are given
access to books and records of the EWG and its affiliates to the
extent that such a commission requires access to perform its
regulatory duties. It allows both registered and exempt utility
holding companies to acquire interests in foreign utility companies
engaged in the generation, transmission or distribution of
electricity or the retail distribution of gas, where a state
commission has certified that it has the ability to protect the
utility's retail ratepayers against adverse investments in foreign
utilities by affiliates of public utilities that such commissions
regulate. State commissions must consider rate making changes and
other regulatory reform to ensure that electric utilities'
investments in energy efficiency and demand side management
programs are at least as profitable as investing in new generating
capacity. FERC has issued a Notice of Proposed Rule Making to
develop regulations under NEPA concerning EWGs and electric
transmission service.
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").
The Company's regulated business operations are likely to be
impacted by the NEPA and FERC Order No. 636. As discussed above,
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 materially adverse impact on the results
of its operations, its financial position or its business
prospects.
Federal Energy Regulatory Commission
SCE&G and GENCO are subject to regulation under the Federal
Power Act, administered by the FERC and the DOE, in the
transmission of electric energy in interstate commerce and in the
sale of electric energy at wholesale for resale, as well as with
respect to licensed hydroelectric projects and certain other
matters, including accounting and the issuance of short-term
promissory notes.
15
SCE&G holds licenses under the Federal Water Power Act or the
Federal Power Act with respect to all its hydroelectric projects.
The expiration dates of the licenses covering the projects are as
follows:
Project Capability (KW) License Expiration Date
Neal Shoals 5,000 1993
Stevens Creek 9,000 1993
Columbia 10,000 2000
Saluda 206,000 2007
Parr Shoals 14,000 2020
Fairfield Pumped Storage 512,000 2020
Pursuant to the provisions of the Federal Power Act as amended
by the Electric Consumers Protection Act of 1986, applications for
new licenses for Neal Shoals and Stevens Creek were filed with the
FERC on December 30, 1991. No competing applications were filed.
The Neal Shoals license application was declared to be ready for
environmental analysis by FERC Notice dated June 3, 1994, and the
Stevens Creek Application was declared to be ready by FERC Notice
dated September 6, 1994. FERC has issued Notices of Authorization
for Continued Project Operation for both projects until FERC has
acted on SCE&G's applications for new licenses. FERC is in the
process of performing a Multiple-project Environmental Assessment
for Neal Shoals, and a Single-project Environmental Assessment for
Stevens Creek.
At the termination of a license under the Federal Power Act,
the United States government may take over the project covered
thereby, or the FERC may extend the license or issue a license to
another applicant. If the United States takes over a project or
the FERC issues a license to another applicant, the original
licensee shall be paid its net investment in the project, not to
exceed fair value, plus severance damages.
Nuclear Regulatory Commission
SCE&G is subject to regulation by the NRC with respect to the
ownership and operation of Summer Station. The NRC's jurisdiction
encompasses broad supervisory and regulatory powers over the
construction and operation of nuclear reactors, including matters
of health and safety, antitrust considerations and environmental
impact. The NRC conducts semiannual reviews that identify plants
that have demonstrated an excellent level of safety performance.
For the sixth consecutive time, the NRC named Summer Station to its
short list of top performing plants.
In addition, the Federal Emergency Management Agency is
responsible for the review, in conjunction with the NRC, of certain
aspects of emergency planning relating to the operation of nuclear
plants.
RATE MATTERS
The following table presents a summary of significant rate
activity for the years 1990 - 1994 based on test years:
REQUESTED GRANTED
Date of % of
General Rate Application/ Amount % Increase Date of Amount Increase
Applications Hearing (Millions) Requested Order (Millions) Granted
PSC
Electric
Retail 12/07/92 $ 72.0* 11.4% 06/07/93 $ 60.5 84%
Retail 01/03/89 $ 27.2 3.7% 07/03/89 $ 18.2** 67%**
Transit
Fares 03/12/92 $ 1.7 42.0% 09/14/92 $ 1.0 59%
*As modified to reflect lowering of rate of return SCE&G was
seeking.
**Reflects a rate reduction of $3.7 million on January 4, 1993 (see
discussion below) and excludes impact of rate reduction of $7.7
million on January 3, 1990 which corresponds to $7.7 million
reduction in cost-of-service resulting from NRC approval of
extension of Summer Station's operating life to 40 years.
16
On October 27, 1994 the PSC issued an order approving SCE&G'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 SCE&G's gas operations that had
previously been deferred.
On June 7, 1993 the PSC issued an order on SCE&G's pending
electric rate proceeding allowing an authorized return on common
equity of 11.5%, resulting in a 7.4% annual increase in retail
electric rates, or a projected $60.5 million annually, based on a
test year. These rates are to be implemented in two phases over a
two-year period: phase one, effective June 1993, producing $42.0
million annually, and phase two, effective June 1994, producing
$18.5 million annually, based on a test year.
On September 14, 1992 the PSC issued an order granting SCE&G a
$.25 increase in transit fares from $.50 to $.75 in both Columbia
and Charleston, South Carolina; however, the PSC also required $.40
fares for low income customers and denied SCE&G's request to reduce
the number of routes and frequency of service. The new rates were
placed into effect on October 5, 1992. SCE&G has appealed the
PSC's order to the Circuit Court.
Effective with the first billing cycle in December 1991,
SCE&G's gas rate schedules for its residential, small commercial
and small industrial customers have included a weather
normalization adjustment (WNA). The WNA minimizes fluctuations in
gas revenues due to abnormal weather conditions and is subject to
an annual review by the PSC. The PSC order was based on a return
on common equity of 12.25%. On August 26, 1994, the PSC ordered
that the WNA be made permanent.
In May 1989 the PSC approved a volumetric and direct billing
method for Pipeline Corporation to recover take-or-pay costs
incurred from its interstate pipeline suppliers pursuant to FERC-
approved final and non-appealable settlements. In December 1992
the Supreme Court approved Pipeline Corporation's full recovery of
the take-or-pay charges imposed by its suppliers and treatment of
these charges as a cost of gas. However, the Supreme Court
declared the PSC-approved "purchase deficiency" methodology for
recovery of these costs to be unlawful retroactive ratemaking and
remanded the docket to the PSC to reconsider its recovery
methodology. On April 30, 1994 the PSC issued an order regarding
Pipeline Corporation's recovery of take-or-pay cost incurred
pursuant to FERC-approved settlements with its upstream interstate
pipeline suppliers. This order provided a mechanism for Pipeline
Corporation to recover its take-or-pay cost volumetrically over a
period of approximately 30 months. SCE&G receives a credit for
payments made prior to the April 30 order which is netted against
the current volumetric surcharge. That net cost is recovered by
SCE&G through its purchased gas adjustment clause.
On August 8, 1990 the PSC issued an order effective November 1,
1990, approving changes in Pipeline Corporation's gas rate design
for sales for resale service and upholding the "value-of-service"
method of regulation for its direct industrial service. Direct
industrial customers seeking "cost-of-service" based rates
initiated two separate appeals to the Circuit Court, which reversed
and remanded to the PSC its August 8, 1990 order. Pipeline
Corporation appealed that decision to the Supreme Court which on
January 10, 1994 reversed the two Circuit Court decisions and
reinstated the PSC Order. The Supreme Court held that the
industrial customer group's appeal was premature and failed to
exhaust administrative remedies. Additionally, the Supreme Court
interpreted the rate-making statutes of South Carolina to give
discretion to the PSC in selecting the methodology to be used in
setting rates for natural gas service.
On July 3, 1989 the PSC granted SCE&G approximately $21.9
million of a requested $27.2 million annual increase in retail
electric revenues based upon an allowed return on common equity of
13.25%. The Consumer Advocate appealed the decision to the Supreme
Court which, on August 31, 1992, found that the evidence in the
record of that case did not support a return on common equity
higher than 13.0% and remanded to the PSC a portion of its July
1989 order for a determination of the proper return on common
equity consistent with the Supreme Court's opinion. On January 19,
1993 the PSC issued an order allowing a return on common equity of
13.0%, approving a refund based on the difference in rates created
by the difference between the 13.0% and the 13.25% return on common
equity and making other non-material adjustments to the calculation
of cost-of-service. The total refund, before interest and income
taxes, was approximately $14.6 million and was charged against 1992
"Electric Revenues." The refund plus interest was made during
1993.
17
Fuel Cost Recovery Procedures
The PSC has established a fuel cost recovery procedure which
determines the fuel component in SCE&G'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. SCE&G has the right to
request a formal proceeding at any time should circumstances
dictate such a review.
In the April 1994 semiannual review of the fuel cost component
of electric rates, the PSC voted to increase the rate from 13.0
mills per KWH to 14.16 mills per KWH, a monthly increase of $1.16
for an average customer using 1,000 KWH per month. For the October
1994 review the PSC voted to continue the rate of 14.16 mills per
KWH.
SCE&G's gas rate schedules and contracts include mechanisms
which allow it to recover from its customers changes in the actual
cost of gas. SCE&G's firm gas rates allow for the recovery of a
fixed cost of gas, based on projections, as established by the PSC
in annual gas cost and gas purchase practice hearings. Any
differences between actual and projected gas costs are deferred and
included when projecting gas costs during the next annual gas cost
recovery hearing.
In the October 1994 review the PSC authorized an increase in
the base cost of gas from 47.100 cents per therm to 51.058 cents
per therm which resulted in a monthly increase of $3.96 (including
applicable taxes) based on an average of 100 therms per month on a
residential bill during the heating season.
ENVIRONMENTAL MATTERS
General
Federal and state authorities have imposed upon the Company
environmental regulations and standards relating primarily to air
emissions, wastewater discharges and solid, toxic and hazardous
waste management. It is difficult to forecast the ultimate effect
of these regulations and standards upon existing and proposed
operations. Moreover, developments in these areas may require that
equipment and facilities be modified, supplemented or replaced.
Capital Expenditures
In the years 1992 through 1994, capital expenditures for
environmental control amounted to approximately $105.0 million.
In addition, approximately $11.1 million, $9.4 million, and $7.9
million of environmental control expenditures were made during
1994, 1993 and 1992, respectively, which are 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 $37.4 million for 1995 and
$215.9 million for the four-year period 1996 through 1999. These
expenditures are included in the Company's construction program.
18
Air Quality Control
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by the
year 2000. These requirements are being phased in over two
periods. The first phase has a compliance date of January 1, 1995
and the second, January 1, 2000. The Company meets all
requirements of Phase I and, therefore, will not have to implement
changes until compliance with Phase II requirements is necessary.
The Company then will most likely meet its compliance requirements
through the burning of natural gas and/or lower sulfur coal, the
addition of scrubbers to coal-fired generating units, and the
purchase of sulfur dioxide emission allowances. At December 31,
1994, the Company had purchased $19.4 million in emission
allowances and had commitments to purchase $6.8 million in emission
allowances in 1995. Low nitrogen oxide burners will be installed
to reduce nitrogen oxide emissions.
The Company is continuing to refine a compliance plan that
must be filed with the EPA by January 1, 1996. The Company
currently estimates that air emissions control equipment will
require capital expenditures of $158 million over the 1995-1999
period to retrofit existing facilities and an increased operation
and maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2004, the Company
anticipates total capital expenditures of $287 million.
Water Quality Control
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a national
permit program. Discharge permits have been issued for all and
renewed for nearly all of SCE&G's and GENCO's generating units.
Concurrent with renewal of these permits the permitting agency has
implemented a more rigorous control program. The Company has been
developing compliance plans to meet the additional parameters of
control and compliance has involved updating wastewater treatment
technologies. Amendments to the Clean Water Act proposed recently
in Congress include several provisions which could prove costly to
SCE&G. These include limitations to mixing zones and the
implementation of technology-based standards.
Superfund Act and Environmental Assessment Program
As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program to
identify and assess current and former operations sites that could
require environmental cleanup. As site assessments are initiated,
an estimate is made of the amount of expenditures, if any,
necessary to investigate and clean up each site. These estimates
are refined as additional information becomes available; therefore
actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site
assessments and cleanup relate primarily to regulated operations;
such amounts have been deferred and are being amortized and
recovered through rates over a ten-year period for electric
operations and an eight-year period for gas operations. Such
deferred amounts totaled $20.2 million and $19.6 million at
December 31, 1994 and 1993, respectively. Estimates to date
include, among other things, the costs estimated to be associated
with the matters discussed in the following paragraphs.
The Company's principal subsidiary, SCE&G, owns five
decommissioned manufactured gas plant sites which contain residues
of by-product chemicals. SCE&G has maintained an active review of
the sites to monitor the nature and extent of the residual
contamination.
19
In September 1992 the EPA notified SCE&G, the City of
Charleston and the Charleston Housing Authority of their potential
liability for the investigation and cleanup of the Calhoun Park
Area Site in Charleston, South Carolina. This site originally
encompassed approximately 18 acres and included properties which
were the locations for industrial operations, including a wood
preserving (creosote) plant and one of SCE&G'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 (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 field work began November 1, 1993 after final
approval and authorization was granted by EPA. SCE&G 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 SCE&G that it considers SCE&G 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. SCE&G 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.
SCE&G has been listed as a PRP and has recorded liabilities,
which are not considered material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina, the Aqua-Tech
Environmental Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina.
The Arkansas Department of Pollution Control and Ecology
(ADPCE) has identified SCE&G as a PRP for clean-up of PCBs at an
abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from ADPCE has been received concerning this
issue. SCE&G does not believe that the resolution of this issue
will have a material effect on SCE&G's results of operations or
financial position.
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of
1991 requires promulgation of regulations addressing specified
subjects, one of which affects the management of industrial solid
waste. This regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation, if adopted as a final regulation in its present form,
could significantly impact SCE&G's and GENCO's engineering, design
and operation of existing and future ash management facilities.
Potential cost impacts could be substantial.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 requires that the United
States government make available by 1998 a permanent repository for
high level radioactive waste and spent nuclear fuel and imposes a
fee of 1.0 mill per KWH of net nuclear generation after April 7,
1983. Payments, which began in 1983, are subject to change and
will extend through the operating life of SCE&G's Summer Station.
SCE&G 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. SCE&G has on-site spent
fuel storage capability until at least 2008 and expects to be able
to expand its storage capacity to accommodate the spent fuel output
for the life of the plant through rod consolidation, dry cask
storage or other technology as it becomes available. The Act also
imposes on utilities the primary responsibility for storage of
their spent nuclear fuel until the repository is available.
20
OTHER MATTERS
With regard to SCE&G's insurance coverage for Summer Station,
reference is made to Note 10B of Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
The Company's net investment in oil and gas properties is
subject to a quarterly ceiling limitation calculation that is based
on the future net revenues from forecasted production of proved oil
and gas reserves valued at current or contract prices. Carrying
values of proved reserves in excess of the ceiling limitation are
expensed currently.
In an effort to limit exposure to changing natural gas prices
and to avoid a writedown resulting from the application of the
ceiling test at December 31, 1994, in January 1995 the Company
entered into a series of forward contacts relating to natural gas
production. These forward contracts have the effect of stabilizing
the price that the Company will receive on approximately sixty
percent of its forecasted natural gas production for the years
1995-2001. The forward contracts are at an average price of $1.88
per dekatherm. If market prices exceed the forward contracts'
prices at the time of delivery, the Company will forego additional
revenues to the extent of the price differential for the quantities
subject to such forward contracts. However, the Company believes
these forward contracts are appropriate in light of current market
conditions and that the forward contracts reduce the Company's
exposure to price risk. The Company remains exposed to price risk
for any production that is not subject to such forward contracts.
ITEM 2. PROPERTIES
SCANA owns no property other than the capital stock of each of
its subsidiaries. It owns all of the capital stock of each
subsidiary except for the Preferred Stock of SCE&G and the capital
stock of SCANA's indirect, wholly owned subsidiaries which are not
material individually or in the aggregate. The assets formerly
belonging to Peoples, acquired by SCANA Corporation in 1990, were
transferred to SCE&G on January 1, 1994.
SCE&G'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. GENCO's Williams Station is subject to a first mortgage
lien.
For a brief description of the properties of the Company's
other subsidiaries, which are not significant as defined in Rule 1-
02 of Regulation S-X, see Item 1, "Business."
21
ELECTRIC
The following table gives information with respect to electric
generating facilities, all of which are owned by SCE&G except as
noted.
Net Generating
Present Year Capability
Facility Fuel Capability Location In-Service (KW)(1)
Steam (2)
Urquhart Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 430,000
Wateree Coal Eastover, SC 1970 700,000
Williams (3) Coal Goose Creek, SC 1973 560,000
Summer (4) Nuclear Parr, SC 1984 590,000
Gas Turbines
Burton Gas/Oil Burton, SC 1961 28,500
Faber Place Gas Charleston, SC 1961 9,500
Hardeeville Oil Hardeeville, SC 1968 14,000
Canadys Gas/Oil Canadys, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (5) Gas/Oil Parr, SC 1970 60,000
Williams (6) Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000
Hydro
Neal Shoals Carlisle, SC 1905 5,000
Parr Shoals Parr, SC 1914 14,000
Stevens Creek Martinez, GA 1914 9,000
Columbia Columbia, SC 1927 10,000
Saluda Irmo, SC 1930 206,000
Pumped Storage
Fairfield Parr, SC 1978 512,000
Total 3,876,000
(1) Summer rating.
(2) Excludes Cope Electric Generating Station, a 385,000 KW plant
currently under construction and scheduled for commercial
operation in early 1996.
(3) The steam unit at Williams Station, owned by GENCO, was
converted from oil-fired to coal-fired operation in 1984 and,
with modifications, can be reconverted to oil-fired operation
should the need arise.
(4) Represents SCE&G's two-thirds portion of the Summer Station.
(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.
(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.
22
SCE&G owns 445 substations having an aggregate transformer
capacity of 18,885,437 KVA. The transmission system consists of 3,057
miles of lines and the distribution system consists of 15,421 pole
miles of lines and 3,122 trench miles of underground lines.
GAS
Natural Gas
SCE&G's gas system, including the Peoples system acquired by
SCANA and transferred to SCE&G on January 1, 1994, consists of
approximately 6,719 miles of three-inch equivalent distribution
pipelines and approximately 11,078 miles of distribution mains and
related service facilities.
Pipeline Corporation's gas system consists of approximately 1,759
miles of transmission pipeline of up to 24 inches in diameter which
connect its resale customers' distribution systems with transmission
systems of Southern Natural and Transco.
Pipeline Corporation owns two LNG plants, one located near
Charleston, South Carolina the other in Salley, South Carolina. The
Charleston facility can liquefy up to 6,000 MCF per day and store the
liquefied equivalent of 1,000,000 MCF of natural gas. The Salley
facility, which became operational in 1994, can store the liquefied
equivalent of 900,000 MCF of natural gas and has no liquefying
capabilities. On peak days, the Charleston facility can regasify up
to 60,000 MCF per day and the Salley facility can regasify up to
90,000 MCF.
Petroleum Resources owns and/or operates oil and gas properties
in Texas, Louisiana, Mississippi, Oklahoma, California, Arkansas,
Nebraska, Kansas, New Mexico, Alabama, Wyoming and Utah and Federal
waters offshore Texas, Louisiana and Alabama.
Propane
SCE&G 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
SCE&G owns 97 motor coaches which operate on a route system of
285 miles.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1.,
"BUSINESS" and Note 10 of Notes to Consolidated Financial Statements
appearing in Item 8., "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
23
CORPORATE STRUCTURE
SCANA CORPORATION
A Holding Company, Owning Twelve
Direct, Wholly Owned Subsidiaries
SOUTH CAROLINA SCANA HYDROCARBONS, INC.
ELECTRIC & GAS COMPANY Markets natural gas as well
Generates and sells electricity as other light hydrocarbons
to wholesale and retail customers, and owns and operates a natural
purchases, sells and transports gas gathering system in Oklahoma.
natural gas at retail and provides Owns and operates a propane
public transit service in Columbia pipeline and provides for
and Charleston. transportation and bulk
storage of propane.
SOUTH CAROLINA GENERATING
COMPANY, INC. SCANA PETROLEUM RESOURCES, INC.
Owns and operates Williams Owns and/or operates oil and gas
Station and sells electricity properties.
to SCE&G.
SERVICECARE, INC.
SOUTH CAROLINA FUEL Provides energy related products
COMPANY, INC. and services beyond the energy
Acquires, owns and provides for meter, principally service
financing for SCE&G's nuclear contracts on home appliances.
fuel, fossil fuel and sulfur
dioxide emission allowances. PRIMESOUTH, INC.
Engages in power plant
SUBURBAN PROPANE GROUP, INC. management and maintenance
Purchases, delivers and services.
sells propane.
SCANA DEVELOPMENT CORPORATION
SCANA CAPITAL RESOURCES, INC. Engaged in the acquisition,
Has provided equity capital development, management and
for diversified investments. sale of real estate. (In
liquidation.)
MPX SYSTEMS, INC.
Provides fiber optic SOUTH CAROLINA PIPELINE
telecommunications, video CORPORATION
conferencing, specialized Purchases, sells and transports
mobile radio services and is natural gas to wholesale and
pursuing Personal Communication direct industrial customers.
Services licenses for wireless Owns and operates two LNG plants
communications. for the liquefaction, regasifi-
cation and storage of natural gas.
Each of the above listed companies is organized and incorporated under the
laws of the State of South Carolina.
24
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers are elected at the annual
organizational meeting of the Board of Directors, held immediately
after the annual meeting of stockholders, 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. 63 Chairman of the Board,
Chief Executive Officer
and President *-present
W.B. Timmerman 48 Executive Vice President 1994-present
Assistant Secretary 1993-present
Senior Vice President *-1994
Chief Financial Officer
and Controller *-present
B.D. Kenyon 52 President and Chief
Operating Officer - SCE&G 1990-present
Senior Vice President -
Division Operations,
Pennsylvania Power and
Light Company *-1990
A. H. Gibbes 48 Senior Vice President - 1994-present
SCANA and
Assistant Secretary - SCE&G
GENCO, Fuel Company, MPX,
PrimeSouth, ServiceCare
and SCANA Development Corp.
General Counsel and
Assistant Secretary 1993-present
President and Treasurer -
SCANA Development Corp. 1990-present
C.B. Novinger 45 Senior Vice President -
Administration *-present
Max Earwood 62 President and Treasurer -
South Carolina Pipeline
Corporation *-present
President and Treasurer -
SCANA Hydrocarbons, Inc.;
SCANA Petroleum Resources,
Inc.; *-present
Vice President - Gas
Distribution, SCE&G *-1991
K.B. Marsh 39 Vice President - Finance,
Treasurer & Secretary 1992-present
Vice President of
Corporate Planning - SCE&G 1991
Vice President and
Controller - SCE&G 1989-1991
*Indicates position held at least since March 1, 1990
25
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS
COMMON STOCK INFORMATION
1994 1993
4th 3rd 2nd 1st 4th 3rd 2nd 1st
Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr.
Price Range: (a)
High 44 5/8 46 46 1/2 50 1/8 52 1/4 51 7/8 48 3/8 46 1/2
Low 41 42 3/4 42 1/8 44 3/4 47 7/8 47 5/8 45 40 1/8
Dividends Per Share:
1994 Amount Date Declared Date Paid
First Quarter $.705 February 15,1994 April 1, 1994
Second Quarter .705 April 28, 1994 July 1, 1994
Third Quarter .705 August 24, 1994 October 1, 1994
Fourth Quarter .705 October 18, 1994 January 1, 1995
1993 Amount Date Declared Date Paid
First Quarter $.685 February 16, 1993 April 1, 1993
Second Quarter .685 April 29, 1993 July 1, 1993
Third Quarter .685 August 25, 1993 October 1, 1993
Fourth Quarter .685 October 19, 1993 January 1, 1994
December 31,
1994 1993
Number of common shares outstanding 48,017,510 46,619,457
Number of common stockholders of record 39,516 41,564
The principal market for SCANA common stock is the New York Stock Exchange. The ticker
symbol used is SCG. The corporate name SCANA is used in newspaper stock listings.
The total number of shares of SCANA common stock outstanding at February 28, 1995 was
48,330,982.
(a) As reported on the New York Stock Exchange Composite Listing.
SECURITIES RATINGS (As of December 31, 1994)
SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY
Rating First Mortgage First and Refunding Preferred Commercial
Agency Medium-Term Notes Bonds Mortgage Bonds Stock Paper
Duff &
Phelps NR A+ A+ A NR
Moody's A3 A1 A1 a1 P-1
Standard
& Poor's A- A A A- A-1
NR - Not Rated
Further reference is made to Note 5 of Notes to Consolidated Financial Statements.
26
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
For the Years Ended December 31, 1994 1993 1992 1991 1990 1984
Statement of Income Data (Thousands of dollars except statistics and per share amounts)
Operating Revenues:
Electric $ 975,388 $ 940,121 $ 829,477 $ 867,215 $ 851,146 $ 755,502
Gas 342,672 320,195 305,275 276,742 292,380 378,491
Transit 4,002 3,851 3,623 3,869 4,033 3,178
Total Operating Revenues 1,322,062 1,264,167 1,138,375 1,147,826 1,147,559 1,137,171
Operating Expenses:
Fuel used in electric generation
and purchased power 255,240 242,793 213,474 234,683 223,972 235,246
Gas purchased for resale 220,923 208,695 191,577 171,869 191,939 289,212
Other operation and maintenance 293,721 290,891 281,242 270,213 265,887 184,727
Depreciation and amortization 119,177 112,844 108,315 102,669 97,801 74,914
Taxes 173,448 163,633 133,987 146,032 142,003 153,776
Total Operating Expenses 1,062,509 1,018,856 928,595 925,466 921,602 937,875
Operating Income 259,553 245,311 209,780 222,360 225,957 199,296
Other Income 5,998 30,076 11,883 11,655 54,874 17,647
Income Before Interest Charges and
Preferred Stock Dividends 265,551 275,387 221,663 234,015 280,831 216,943
Interest Charges, Net 108,397 101,189 97,600 91,458 92,317 78,248
Preferred Stock Cash Dividends
of Subsidiary 5,955 6,217 6,473 6,706 6,911 16,877
Net Income $ 151,199 $ 167,981 $ 117,590 $ 135,851 $ 181,603 $ 121,818
Percent of Operating Income (Loss)
Before Income Taxes
Electric 88% 90% 85% 89% 89% 87%
Gas 14% 13% 18% 14% 14% 15%
Transit (2%) (3%) (3%) (3%) (3%) (2%)
Common Stock Data
Weighted Average Number of Common
Shares Outstanding (Thousands) 47,381 45,203 41,475 40,361 40,882 39,900
Earnings Per Weighted Average
Share of Common Stock $3.19 $3.72 $2.84 $3.37 $4.44 $3.05
Dividends Declared Per Share
of Common Stock $2.82 $2.74 $2.68 $2.62 $2.52 $2.05
Common Shares Outstanding
(Year-End) (Thousands) 48,018 46,619 43,911 40,784 40,882 40,296
Book Value Per Share of
Common Stock (Year-End) $29.37 $28.59 $26.46 $25.23 $24.56 $19.31
27
December 31, 1994 1993 1992 1991 1990 1984
Balance Sheet Data (Thousands of dollars except statistics and per share amounts)
Utility Plant, Net $3,293,667 $3,004,075 $2,810,279 $2,664,651 $2,549,763 $2,205,297
Total Assets $4,393,128 $4,040,526 $3,557,721 $3,305,862 $3,144,936 $2,506,996
Common Equity $1,410,438 $1,333,045 $1,161,896 $1,028,990 $1,003,877 $ 778,251
Preferred Stock (Not subject
to purchase or sinking fund
requirements) 26,027 26,027 26,027 26,027 26,027 26,262
Preferred Stock, Net (Subject
to purchase or sinking fund
requirements) 49,528 52,840 56,154 59,469 62,704 152,974
Long-Term Debt, Net 1,537,624 1,424,399 1,204,754 1,122,396 938,933 900,878
Total Capitalization $3,023,617 $2,836,311 $2,448,831 $2,236,882 $2,031,541 $1,858,365
Other Statistics
Electric:
Customers (Year-End) 476,412 468,874 461,900 453,660 446,516 378,963
Territorial sales
(Million KWH) 16,838 16,880 15,794 15,695 15,385 12,590
Residential:
Average annual use per
customer (KWH) 13,048 14,077 13,037 13,246 13,330 12,061
Average annual rate
per KWH $.0743 $.0707 $.0695 $.0700 $.0707 $.0757
Generating Capability - Net MW
(Year-End) 3,876 3,864 3,912 3,912 3,891 3,959
Territorial Peak Demand - Net MW 3,444 3,557 3,380 3,300 3,222 2,596
Gas:
Customers (Year-End) 238,614 234,736 231,153 225,819 220,817 189,544
Sales (Thousand Therms) 781,109 717,417 761,721 694,801 711,821 737,059
Residential:
Average annual use per
customer (therms) 543 605 577 521 497 618
Average annual rate
per therm $.84 $.76 $.74 $.77 $.77 $.69
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulatory
protection. The transition began with the enactment of the Public
Utility Regulatory Policies Act of 1978 which facilitated the entry
of competitors into the electric generation business.
Subsequently, the National Energy Policy Act (NEPA) was enacted in
1992 to promote competition among utility and nonutility generators
in the wholesale electric generation market. Recent initiatives in
some states to lessen regulation and promote competition,
particularly with regard to retail transmission access, also have
accelerated the utility industry's transition.
Future deregulation of electric wholesale and retail markets
will create opportunities to compete for new and existing customers
and markets. As a result, profit margins and asset values of some
utilities could be adversely affected.
The pace of deregulation, the future market price of
electricity, and the regulatory actions which may be taken by the
Public Service Commission of South Carolina (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's electric and gas utility,
SCE&G, reorganized its operations around Strategic Business Units.
Maintaining a competitive cost structure is of paramount importance
in the utility's strategic plan. SCE&G has undertaken a variety of
initiatives, including reductions in operations and maintenance
costs and in staffing levels. SCE&G believes that these actions as
well as numerous others that have been and will be taken
demonstrate its ability and commitment to succeed in the new
operating environment to come.
LIQUIDITY AND CAPITAL RESOURCES
The cash requirements of the Company arise primarily from
SCE&G's operational needs, the Company's construction program and
the need to fund the activities or investments of the Company's
nonregulated subsidiaries. The ability of the Company's regulated
subsidiaries to replace existing plant investment, as well as to
expand to meet future demand for electricity and gas, will depend
upon their ability to attract the necessary financial capital on
reasonable terms. The Company's regulated subsidiaries recover 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 regulated
subsidiaries expand their construction programs, 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
the regulated subsidiaries' ability to obtain adequate and timely
rate relief.
Due to continuing customer growth, SCE&G entered into a
contract with Duke/Fluor Daniel in 1991 to design, engineer and
build a 385 MW coal-fired electric generating plant near Cope,
South Carolina in Orangeburg County. Construction of the plant
began in November 1992 and is expected to be complete in late 1995
with commercial operation beginning in early 1996. The estimated
cost of the Cope plant, excluding financing costs and allowance for
funds used during construction (AFC), but including an allowance
for escalation, is $450 million. In addition, the transmission
lines for interconnection with the Company's system are expected to
cost $26 million. Until the completion of the new plant, SCE&G is
contracting for additional capacity as necessary to ensure that the
energy demands of its customers can be met.
As discussed in Note 2B of Notes to Consolidated Financial
Statements, on June 7, 1993 the PSC issued an order granting SCE&G
a 7.4% annual increase in retail electric rates which was
implemented in two phases over a two year period: phase one,
effective June 1993, producing $42.0 million annually, and phase
two, effective June 1994, producing $18.5 million annually, based
on a test year.
29
The estimated primary cash requirements for 1995, excluding
requirements for fuel liabilities and short-term borrowings, and
the actual primary cash requirements for 1994 are as follows:
1995 1994
(Thousands of Dollars)
Property additions and construction
expenditures, excluding allowance for
funds used during construction (AFC) $348,530 $471,175
Acquisition of oil and gas producing
properties - 47,189
Nuclear fuel expenditures 23,084 27,429
Maturing obligations, redemptions and
sinking and purchase fund requirements 25,630 30,373
Total $397,244 $576,166
Approximately 31% of total cash requirements (excluding
dividends) was provided from internal sources in 1994 as compared
to 28% in 1993.
The Company has in effect a medium-term note program for the
issuance from time to time of unsecured medium-term debt
securities. The proceeds from the sales of these securities may be
used to fund additional business activities in nonutility subsidi-
aries, to reduce short-term debt incurred in connection therewith
or for general corporate purposes. In December 1994, a shelf
registration statement filed with the Securities and Exchange
Commission became effective providing for the issuance of up to an
additional $250 million in medium-term notes. At December 31, 1994
the Company had available for issuance $317.6 million.
SCE&G's First and Refunding Mortgage Bond Indenture, dated
April 1, 1945 (Old Mortgage), contains provisions prohibiting the
issuance of additional bonds thereunder (Class A Bonds) unless net
earnings (as therein defined) for 12 consecutive months out of the
15 months prior to the month of issuance are at least twice the
annual interest requirements on all Class A Bonds to be outstanding
(Bond Ratio). For the year ended December 31, 1994 the Bond Ratio
was 3.52. The issuance of additional Class A Bonds is restricted
also to an additional principal amount equal to 60% of unfunded net
property additions (which unfunded net property additions totaled
approximately $499.8 million at December 31, 1994), Class A Bonds
issued on the basis of retirements of Class A Bonds (no earned
retirement credits remaining at December 31, 1994), and Class A
Bonds issued on the basis of cash on deposit with the Trustee.
SCE&G has placed a new bond indenture (New Mortgage) dated
April 1, 1993 on substantially all of its electric properties under
which its future mortgage-backed debt (New Bonds) will be issued.
New Bonds are expected to be issued under the New Mortgage on the
basis of a like principal amount of Class A Bonds issued under the
Old Mortgage which have been deposited with the Trustee of
the New Mortgage (of which $57 million were available for such
purpose as of December 31, 1994), until such time as all presently
outstanding Class A Bonds are retired. Thereafter, New Bonds will
be issuable on the basis of property additions in a principal
amount equal to 70% of the original cost of electric and common
plant properties (compared to 60% of value for Class A Bonds under
the Old Mortgage), cash deposited with the Trustee, and retirement
of New Bonds. New Bonds will be issuable under the New Mortgage
only if adjusted net earnings (as therein defined) for 12
consecutive months out of the 18 months immediately preceding the
month of issuance are at least twice the annual interest
requirements on all outstanding bonds (including Class A Bonds) and
New Bonds to be outstanding (New Bond Ratio). For the year ended
December 31, 1994 the New Bond Ratio was 4.85.
30
The following additional financing transactions have
occurred since December 31, 1993:
, On January 14, 1994 the Company closed unsecured bank
loans totaling $60 million due January 13, 1995, and used the
proceeds to pay off a loan in a like total amount. In
January 1995 the Company refinanced the loans with an
unsecured bank loan of $60 million due January 12, 1996 at an
initial interest rate of 6.44%, subject to reset quarterly at
LIBOR plus ten basis points.
, On July 21, 1994 SCE&G issued $100 million of First Mortgage
Bonds, 7.70% series due July 15, 2004 to repay short-term
borrowings in a like amount.
, On November 3, 1994 SCE&G issued $30 million of Pollution
Control Facilities Revenue Bonds due November 1, 2024. The
proceeds from the sale of the bonds are being used to defray
the cost of constructing certain facilities for the disposal
of solid waste at SCE&G's Cope Generating Station under
construction in Orangeburg County, South Carolina.
Without the consent of at least a majority of the total
voting power of SCE&G's preferred stock, SCE&G 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 SCE&G'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, SCE&G and
GENCO must obtain FERC authority to issue short-term indebtedness.
The FERC has authorized SCE&G to issue up to $200 million of
unsecured promissory notes or commercial paper with maturity
dates of 12 months or less, but not later than December 31, 1997.
GENCO has not sought such authorization.
The Company had $479.1 million authorized lines of credit and
had unused lines of credit of $455.1 million at December 31, 1994.
In addition, SCE&G has a credit agreement for a maximum of $75
million to finance nuclear and fossil fuel inventories, with $24.4
million available at December 31, 1994.
SCE&G's Restated Articles of Incorporation prohibit issuance
of additional shares of preferred stock without consent of the
preferred stockholders unless net earnings (as defined therein) for
the 12 consecutive months immediately preceding the month of
issuance are at least one and one-half times the aggregate of all
interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1994
the Preferred Stock Ratio was 2.29.
On December 16, 1994 the Company registered with the SEC
2,000,000 additional shares of the Company's common stock to be
issued and sold under the SPSP.
During 1994 the Company issued 595,438 shares of the Company's
common stock under the DRP. In addition, the Company issued 781,354
shares of its common stock pursuant to its SPSP. The Company has
authorized and reserved for issuance, and registered under
effective registration statements, 1,470,386 and 2,091,066 shares
of common stock pursuant to the DRP and the SPSP, respectively.
31
In January 1994 the Company signed an agreement to sell
substantially all of the real estate assets of SCANA Development
Corporation to Liberty Properties Group, Inc. of Greenville, South
Carolina for $91.5 million. On March 4, 1994 the Company and
Liberty amended the agreement to exclude certain projects then
under construction, and the sales price was reduced to $49.6
million. The transaction was closed on May 27, 1994. Certain
other assets of SCANA Development Corporation are being sold to
other parties. These transactions did not have a material impact
on the Company's financial position or results of operations.
MPX Systems Inc., a wholly owned subsidiary of SCANA, through
a joint venture with ITC Transmission Systems, a Georgia-based
telecommunications holding company, is constructing a fiber optic
network through Texas, Louisiana, Mississippi, Alabama and
Georgia. The network, which will consist of more than 900 miles of
fiber optic lines, is expected to be completed by June 1995 at a
cost of $58 million. In addition, MPX is pursuing Personal
Communication Services licenses for wireless communications in the
Southeast through a joint venture with ITC Personal Communications,
Inc., Intercel PCS Services, Inc., and South Atlantic PCS
Corporation. A $40 million construction loan obtained by the joint
venture has been guaranteed in part by SCANA Corporation. All new
ventures currently capitalize on the fiber infrastructure in place
and provide for expansion of the network.
The Company anticipates that its 1995 cash requirements of
$397.2 million will be met through internally generated funds
(approximately 42% excluding dividends), the sales of additional
equity securities and the incurrence of additional short-term and
long-term indebtedness. The timing and amount of such financing
will depend upon market conditions and other factors. Actual 1995
expenditures may vary from the estimates set forth above due to
factors such as inflation and economic conditions, regulation and
legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.
The Company expects that it has or can obtain adequate sources
of financing to meet its projected cash requirements.
Environmental Matters
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by the
year 2000. These requirements are being phased in over two
periods. The first phase has a compliance date of January 1, 1995
and the second, January 1, 2000. The Company meets all
requirements of Phase I and, therefore, will not have to implement
changes until compliance with Phase II requirements is necessary.
The Company then will most likely meet its compliance requirements
through the burning of natural gas and/or lower sulfur coal, the
addition of scrubbers to coal-fired generating units, and the
purchase of sulfur dioxide emission allowances. At December 31,
1994, the Company had purchased $19.4 million in emission
allowances and had commitments to purchase $6.8 million in emission
allowances in 1995. Low nitrogen oxide burners will be installed
to reduce nitrogen oxide emissions.
The Company is continuing to refine a compliance plan that
must be filed with the U.S. Environmental Protection Agency (EPA)
by January 1, 1996. The Company currently estimates that air
emissions control equipment will require capital expenditures of
$158 million over the 1995-1999 period to retrofit existing
facilities and an increased operation and maintenance cost of
approximately $1 million per year. To meet compliance
requirements through the year 2004, the Company anticipates
total capital expenditures of $287 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 to meet the additional parameters of
control, and compliance has involved updating wastewater treatment
technologies. Amendments to the Clean Water Act proposed recently
in Congress include several provisions which could prove costly to
SCE&G. These include limitations to mixing zones and the
implementation of technology-based standards.
32
The South Carolina Solid Waste Policy and Management Act of
1991 requires promulgation of regulations addressing specified
subjects, one of which affects the management of industrial solid
waste. This regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation, if adopted as a final regulation in its present form,
could significantly impact SCE&G's and GENCO's engineering, design
and operation of existing and future ash management facilities.
Potential cost impacts could be substantial.
As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program to
identify and assess current and former operations sites that could
require environmental cleanup. As site assessments are initiated,
an estimate is made of the amount of expenditures, if any,
necessary to investigate and clean up each site. These estimates
are refined as additional information becomes available; therefore,
actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site
assessments and cleanup relate primarily to regulated operations;
such amounts have been deferred and are being amortized and
recovered through rates over a ten-year period for electric
operations and a eight-year period for gas operations. Such
deferred amounts totaled $20.2 million and $19.6 million at
December 31, 1994 and 1993, respectively. Estimates to date
include, among other things, the costs associated with the matters
discussed in the following paragraphs.
SCE&G, the Company's principal subsidiary, owns five
decommissioned manufactured gas plant sites which contain residues
of by-product chemicals. SCE&G has maintained an active review of
the sites to monitor the nature and extent of the residual
contamination.
In September 1992 the EPA notified SCE&G, the City of
Charleston and the Charleston Housing Authority of their potential
liability for the investigation and cleanup of the Calhoun Park
Area Site in Charleston, South Carolina. This site originally
encompassed approximately 18 acres and included properties which
were the locations for industrial operations, including a wood
preserving (creosote) plant and one of SCE&G's decommissioned
manufactured gas plants. The original scope of this investigation
has been expanded to approximately 30 acres, including adjacent
properties owned by the National Park Service and the City of
Charleston, and private properties. The site has not been placed
on the National Priority List, but may be added before cleanup is
initiated. The potentially responsible parties (PRP) have agreed
with the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigations process to be
compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study (RI/FS) and a corresponding Scope
of Work. Actual field work began November 1, 1993 after final
approval and authorization was granted by the EPA. SCE&G 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 SCE&G that it considers SCE&G 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. SCE&G 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.
SCE&G has been listed as a PRP and has recorded liabilities,
which are not considered material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina, the Aqua-Tech
Environmental, Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina.
The Arkansas Department of Pollution Control And Ecology
(ADPCE) has identified SCE&G as a PRP for clean-up of PCBs at an
abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from ADPCE has been received concerning this
issue. SCE&G does not believe that the resolution of this issue
will have a material effect on SCE&G's results of operations or
financial position.
33
Regulatory Matters
On June 7, 1993 the PSC issued an order on SCE&G's pending
electric rate proceeding allowing an authorized return on common
equity of 11.5%, resulting in a 7.4% annual increase in retail
electric rates, or a projected $60.5 million annually, based on a
test year. These rates were implemented in two phases over a two-
year period: phase one, effective June 1993, producing $42.0
million annually, and phase two, effective June 1994, producing
$18.5 million annually, based on a test year.
SCE&G anticipates filing for electric rate relief in 1995.
The filing is anticipated to encompass primarily the remaining cost
of completing the construction of the Cope Generating Station.
The Company's regulated business operations are likely to be
impacted by the NEPA and FERC Order No. 636. NEPA is designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. Order No. 636 is intended to deregulate the
markets for interstate sales of natural gas by requiring that
pipelines provide transportation services that are equal in quality
for all gas suppliers whether the customer purchases gas from the
pipeline or another supplier. In the opinion of the Company, it
will be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any
materially adverse impact on the results of its operations, its
financial position or its business prospects.
Other
The Company's net investment in oil and gas properties is
subject to a quarterly ceiling limitation calculation that is based
on the future net revenues from forecasted production of proved oil
and gas reserves valued at current or contract prices. Carrying
values of proved reserves in excess of the ceiling limitation are
expensed currently.
In an effort to limit exposure to changing natural gas prices
and to avoid a writedown resulting from the application of the
ceiling test at December 31, 1994, in January 1995 the Company
entered into a series of forward contacts relating to natural gas
production. These forward contracts have the effect of stabilizing
the price that the Company will receive on approximately sixty
percent of its forecasted natural gas production for the years
1995-2001. The forward contracts are at an average price of $1.88
per dekatherm. If market prices exceed the forward contracts'
prices at the time of delivery, the Company will forego additional
revenues to the extent of the price differential for the quantities
subject to such forward contracts. However, the Company believes
these forward contracts are appropriate in light of current market
conditions and that the forward contracts reduce the Company's
exposure to price risk. The Company remains exposed to price risk
for any production that is not subject to such forward contracts.
34
RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share of common stock, the percent increase
(decrease) from the previous year and the rate of return earned on
common equity for the years 1992 through 1994 were as follows:
1994 1993 1992
Earnings per weighted average share $3.19 $3.72 $2.84
Percent increase (decrease) in earnings
per share (14.2%) 31.0% (15.7%)
Return earned on common equity (year-end) 10.7% 12.6% 10.1%
, 1994 Earnings per share and return on common equity
decreased in 1994 primarily due to operations at Petroleum
Resources, the Company's oil and natural gas exploration
and production subsidiary. Petroleum Resources reported
a net loss of $19.2 million for 1994, including an
after-tax charge of $12.4 million recorded during the third
quarter of 1994 to reflect an adjustment to accumulated
depreciation, depletion and amortization and a writedown of
the carrying value of certain of Petroleum Resources' gas
properties based on a recently completed reserve study.
, 1993 Earnings per share and return on common equity
increased in 1993 primarily due to a higher electric sales
margin and additional nonoperating income.
The Company's financial statements include AFC. AFC is a
utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is
shown on the balance sheet as construction work in progress) is
capitalized. An equity portion of AFC is included in
nonoperating income and a debt portion of AFC is included in
interest charges (credits) as noncash items both of which have
the effect of increasing reported net income. AFC represented
approximately 6.4% of income before income taxes in 1994, 5.7% in
1993 and 5.3% in 1992.
In 1994 SCANA's Board of Directors raised the quarterly cash
dividend on common stock to 70.5 cents per share from 68.5 cents
per share. The increase, effective with the dividend payable on
April 1, 1994, raised the indicated annual dividend rate to $2.82
per share from $2.74. SCANA has increased the dividend rate on
its common stock in 41 of the last 42 years.
Electric Operations
, 1994 The increase in the electric sales margin from 1993
to 1994 is primarily the result of an increase in retail
electric rates phased in over a two-year period beginning
June 1993 and an increase in industrial sales, which more
than offset the negative impact of a six percent decrease
in residential sales of electricity due to milder weather
in 1994.
, 1993 The increase in electric sales margin from 1992 to
1993 is primarily a result of increased residential and
commercial KWH sales due to weather and customer growth, an
increase in retail electric rates beginning in June 1993
and the recording in 1992 of a $14.6 million reserve
against earnings related to the August 31, 1992 retail
electric rate ruling from the Supreme Court (see Note 2G of
Notes to Consolidated Financial Statements).
An increase of 7,538 electric customers to 476,412 total
customers contributed to a 1994 peak demand of 3,444 MW on
January 19. The all time peak demand record of 3,557 MW was set
on July 29, 1993.
35
Gas Operations
, 1994 The 1994 gas sales margin increased from 1993
primarily as a result of lower gas costs which allowed
Pipeline Corporation to compete successfully with alternate
fuel suppliers in industrial markets. Higher oil prices and
a stronger economy had a positive impact on industrial sales
which increased for both SCE&G and Pipeline Corporation.
, 1993 In 1993 the gas sales margin decreased from 1992 as a
result of higher gas prices which reducedPipeline
Corporation's sales due to the competitiveness of alternate
fuels. This reduction was partially offset by increases in
higher margin residential and commercial sales and increased
transportation volumes.
Other Operating Expenses
, 1994 Other operation and maintenance expenses increased for
1994 primarily due to an increase in the costs of
postretirement benefits other than pensions which are
accrued in accordance with Financial Accounting Standards
Board Statement No. 106 (See Note 1J of Notes to
Consolidated Financial Statements.) The increase in
depreciation and amortization expenses is attributable to
property additions and to increases in depreciation rates.
The increase in other taxes reflects an increase in SCE&G's
property taxes of approximately $5 million.
, 1993 Other operation and maintenance expenses increased for
1993 primarily due to the implementation of Financial
Accounting Standards Board Statement No. 106 (see Note 1J of
Notes to Consolidated Financial Statements) pursuant to the
June 1993 PSC electric rate order and the amortization of
environmental expenses. The depreciation and amortization
increase reflects additions to plant in service. The
increase in income taxes corresponds to the increase in
income and reflects the increase in the corporate tax rate
from 34% to 35% retroactive to January 1, 1993.
Other Income
Other income, net of taxes, decreased approximately $23.3
million in 1994 primarily due to operations at Petroleum
Resources. Petroleum Resources reported a net loss of $19.2
million for 1994 including an after-tax charge of $12.4 million
recorded during the third quarter of 1994 to reflect an
adjustment to accumulated depreciation, depletion, and
amortization and a writedown of the carrying value of certain
Petroleum Resources gas properties based on recently completed
reserve study. In 1993 Petroleum Resources reported net income
of $11.1 million.
The Company's net investment in oil and gas properties is
subject to a quarterly ceiling limitation calculation that is
based on the future net revenues from forecasted production of
proved oil and gas reserves valued at current or contract prices.
Carrying values of proved reserves in excess of the ceiling
limitation are expensed currently.
In an effort to limit exposure to changing natural gas
prices and to avoid a writedown resulting from the application of
the ceiling test at December 31, 1994, in January 1995 the
Company entered into a series of forward contacts relating to
natural gas production. These forward contracts have the effect
of stabilizing the price that the Company will receive on
approximately sixty percent of its forecasted natural gas
production for the years 1995-2001. The forward contracts are at
an average price of $1.88 per dekatherm. If market prices exceed
the forward contracts' prices at the time of delivery, the
Company will forego additional revenues to the extent of the
price differential for the quantities subject to such forward
contracts. However, the Company believes these forward contracts
are reasonable in light of current market conditions and that the
forward contracts reduce the Company's exposure to price risk.
The Company remains exposed to price risk for any production that
is not subject to such forward contracts.
36
Interest Expense
, 1994 The increase in interest expense (excluding the debt component of
(AFC) is primarily attributable to the issuance of $100 million of First
Mortgage Bonds in July and $30 million of Pollution Control Facilities
Revenue Bonds in November, both to finance utility construction, and to
the issuance of long-term debt during 1993.
, 1993 Interest on long-term debt increased approximately $5.6 million in
1993 compared to 1992 due to the issuance of $72.4 million medium-
term notes during the latter part of 1992 and $60 million medium-term
notes in July 1993 to finance acquisitions of natural gas reserves and
the issuance of $200 million of SCE&G's First Mortgage Bonds to finance
utility construction. The resulting increases more than offset the
interest savings resulting from the redemption and refinancing of $382
million of First and Refunding Mortgage Bonds with the proceeds from the
issuance of $400 million of First Mortgage Bonds by SCE&G at lower
interest rates.
37
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditor's Report....................................... 39
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1994 and 1993... 40
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1994, 1993 and 1992............. 42
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992............................. 43
Consolidated Statements of Capitalization as of
December 31, 1994 and 1993................................... 44
Notes to Consolidated Financial Statements..................... 46
Supplemental financial statement schedules are omitted because of the
absence of conditions under which they are required or because the required
information is included in the consolidated financial statements or in the
notes thereto.
38
INDEPENDENT AUDITORS' REPORT
SCANA CORPORATION:
We have audited the accompanying Consolidated Balance Sheets
and Consolidated Statements of Capitalization of SCANA
Corporation and subsidiaries (Company) as of December 31, 1994
and 1993 and the related Consolidated Statements of Income and
Retained Earnings and of Cash Flows for each of the three years
in the period ended December 31, 1994. These financial
statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements
present fairly, in all material respects, the financial position
of the Company at December 31, 1994 and 1993, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 1994 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 6, 1995
39
CONSOLIDATED BALANCE SHEETS
December 31, 1994 1993
ASSETS (Thousands of Dollars)
Utility Plant (Notes 1, 3 and 4):
Electric $3,424,951 $3,328,915
Gas 467,576 451,493
Transit 3,785 3,769
Common 77,327 72,804
Total 3,973,639 3,856,981
Less accumulated depreciation and amortization 1,333,360 1,259,689
Total 2,640,279 2,597,292
Construction work in progress 582,628 349,530
Nuclear fuel, net of accumulated amortization 43,591 29,087
Acquisition adjustment-gas, net of accumulated amortization 27,169 28,166
Utility Plant, Net 3,293,667 3,004,075
Nonutility Property and Investments (Net of accumulated
depreciation and depletion)(Note 1) 395,929 393,728
Current Assets:
Cash and temporary cash investments (Note 8) 10,934 20,766
Receivables 183,180 174,121
Inventories (at average cost):
Fuel (Notes 3 and 4) 60,273 62,977
Materials and supplies 47,463 46,890
Prepayments 19,853 21,826
Accumulated deferred income taxes 18,629 8,607
Total Current Assets 340,332 335,187
Deferred Debits:
Emission allowances 19,409 -
Unamortized debt expense 13,488 13,076
Unamortized deferred return on plant investment (Note 1) 10,614 14,860
Nuclear plant decommissioning fund (Note 1) 30,383 25,103
Other (Notes 1 and 10) 289,306 254,497
Total Deferred Debits 363,200 307,536
Total $4,393,128 $4,040,526
40
December 31, 1994 1993
CAPITALIZATION AND LIABILITIES (Thousands of Dollars)
Stockholders' Investment (Note 5):
Common equity $1,410,438 $1,333,045
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,436,465 1,359,072
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 49,528 52,840
Long-Term Debt, Net (Notes 3, 4 and 8) 1,537,624 1,424,399
Total Capitalization 3,023,617 2,836,311
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 183,027 43,019
Current portion of long-term debt (Note 3) 38,055 34,322
Current portion of preferred stock (Note 6) 2,418 2,504
Accounts payable 117,959 129,495
Estimated rate refunds and related interest (Note 2) - 2,509
Customer deposits 13,768 13,498
Taxes accrued 46,670 50,063
Interest accrued 25,226 21,784
Dividends declared 35,530 33,637
Other 17,220 12,649
Total Current Liabilities 479,873 343,480
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 589,026 568,172
Accumulated deferred investment tax credits (Notes 1 and 7) 91,349 94,981
Accumulated reserve for nuclear plant decommissioning (Note 1) 30,383 25,103
Other (Note 1) 178,880 172,479
Total Deferred Credits 889,638 860,735
Commitments and Contingencies (Note 10) - -
Total $4,393,128 $4,040,526
See Notes to Consolidated Financial Statements.
41
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1994 1993 1992
(Thousands of Dollars
except per share amounts)
Operating Revenues (Notes 1 and 2):
Electric $ 975,388 $ 940,121 $ 829,477
Gas 342,672 320,195 305,275
Transit 4,002 3,851 3,623
Total Operating Revenues 1,322,062 1,264,167 1,138,375
Operating Expenses:
Fuel used in electric generation 235,136 229,736 206,151
Purchased power 20,104 13,057 7,323
Gas purchased for resale 220,923 208,695 191,577
Other operation (Note 1) 229,996 223,239 215,800
Maintenance (Note 1) 63,725 67,652 65,442
Depreciation and amortization (Note 1) 119,177 112,844 108,315
Income taxes (Notes 1 and 7) 94,510 90,007 60,947
Other taxes 78,938 73,626 73,040
Total Operating Expenses 1,062,509 1,018,856 928,595
Operating Income 259,553 245,311 209,780
Other Income (Note 1):
Other income (loss), net of income taxes (2,178) 21,147 6,388
Allowance for equity funds used during construction 8,176 8,929 5,495
Total Other Income 5,998 30,076 11,883
Income Before Interest Charges
and Preferred Stock Dividends 265,551 275,387 221,663
Interest Charges (Credits):
Interest on long-term debt, net 108,804 98,695 93,052
Other interest expense 6,749 8,672 8,819
Allowance for borrowed funds used
during construction (Note 1) (7,156) (6,178) (4,271)
Total Interest Charges, Net 108,397 101,189 97,600
Income Before Preferred Stock Cash
Dividends of Subsidiary 157,154 174,198 124,063
Preferred Stock Cash Dividends of
Subsidiary (At stated rates) (5,955) (6,217) (6,473)
Net Income 151,199 167,981 117,590
Retained Earnings at Beginning of Year 506,380 462,893 457,393
Common Stock Cash Dividends Declared (Note 5) (133,911) (124,494) (112,090)
Retained Earnings at End of Year $ 523,668 $ 506,380 $ 462,893
Net Income $ 151,199 $ 167,981 $ 117,590
Weighted Average Number of Common Shares
Outstanding (Thousands) 47,381 45,203 41,475
Earnings Per Weighted Average Share of Common Stock $3.19 $3.72 $2.84
See Notes to Consolidated Financial Statements.
42
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994 1993 1992
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $151,199 $167,981 $117,590
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization 210,905 158,024 126,695
Amortization of nuclear fuel 13,487 18,156 23,190
Deferred income taxes, net 9,967 65,205 (10,783)
Deferred investment tax credits, net (3,632) (3,658) (3,667)
Net regulatory asset - adoption of SFAS No. 109 (1,951) (31,531) -
Dividends declared on preferred stock of subsidiary 5,955 6,217 6,473
Allowance for funds used during construction (15,332) (15,107) (9,766)
Unamortized loss on reacquired debt (60) (17,063) (81)
Nuclear refueling accrual (4,881) (6,086) 11,862
Equity in (earnings) losses of investees (230) (319) 652
Over (under) collections, fuel adjustment clause (16,966) (14,308) 7,482
Emission allowances (19,409) - -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (9,059) (35,244) (8,918)
(Increase) decrease in inventories 2,131 (10,995) (234)
Increase (decrease) in accounts payable (11,536) 28,109 7,282
Increase (decrease) in estimated rate
refunds and related interest (2,509) (15,302) 17,811
Increase (decrease) in taxes accrued (3,393) (14,941) 1,691
Increase (decrease) in interest accrued 3,442 (7,511) 663
Other, net (11,423) 3,955 12,354
Net Cash Provided From Operating Activities 296,705 275,582 300,296
Cash Flows From Investing Activities:
Utility property additions and construction expenditures (404,600) (322,381) (277,636)
(Increase) decrease in nonutility property and investments:
Acquisition of oil and gas producing properties (47,189) (122,621) (74,766)
Nonutility property (109,336) (81,044) (35,462)
Investments (19,006) (4,066) (2,591)
Sale of Real Estate Assets 79,439 - -
Principal noncash item:
Allowance for funds used during construction 15,332 15,107 9,766
Net Cash Used For Investing Activities (485,360) (515,005) (380,689)
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds 100,000 600,000 -
Issuance of common stock 63,317 129,066 126,809
Issuance of notes and loans 60,000 148,059 154,254
Issuance of pollution control bonds 30,000 - -
Other long-term debt - 3,005 -
Repayments:
Mortgage bonds - (430,000) (35,890)
Notes (75,545) (72,040) (95,272)
Other long-term debt (11,430) (1,195) (255)
Preferred stock (3,398) (3,295) (3,199)
Dividend payments:
Common stock (131,925) (122,129) (109,383)
Preferred stock (6,048) (6,247) (6,558)
Short-term borrowings, net 140,008 1,863 20,390
Fuel financings, net 13,844 (18,948) (6,628)
Net Cash Provided By Financing Activities 178,823 228,139 44,268
Net Decrease in Cash and Temporary Cash Investments (9,832) (11,284) (36,125)
Cash and Temporary Cash Investments, January 1 20,766 32,050 68,175
Cash and Temporary Cash Investments, December 31 $ 10,934 $ 20,766 $ 32,050
Supplemental Cash Flows Information:
Cash paid for - Interest $110,347 $113,010 $100,340
- Income taxes 90,012 93,337 81,819
Noncash Financing Activities:
Department of Energy decontamination and
decommissioning obligation - 4,965 -
See Notes to Consolidated Financial Statements.
43
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1994 1993
Common Equity (Note 5): (Thousands of Dollars)
Common stock, without par value, authorized 75,000,000 shares; issued
and outstanding, 1994 - 48,017,510 shares and 1993 - 46,619,457 shares $ 886,770 $ 826,665
Retained earnings 523,668 506,380
Total Common Equity 1,410,438 46% 1,333,045 47%
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5):
$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
$100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767
$50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260
Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1%
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8):
$100 Par Value - Authorized 1,550,000 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
7.70% 89,984 92,992 101.00 - 101.00 8,998 9,299
8.12% 126,835 131,899 102.03 - 102.03 12,684 13,190
216,819 224,891
$50 Par Value - Authorized 1,627,074 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
4.50% 19,088 20,800 51.00 - 51.00 954 1,040
4.60% 2,334 3,834 50.50 - 50.50 117 192
4.60%(A) 28,052 30,052 51.00 - 51.00 1,403 1,503
4.60%(B) 78,200 81,600 50.50 - 50.50 3,910 4,080
5.125% 73,000 74,000 51.00 - 51.00 3,650 3,700
6.00% 86,400 89,600 50.50 - 50.50 4,320 4,480
8.72% 127,956 160,000 51.00 12-31-98 50.00 6,398 8,000
9.40% 190,245 197,191 51.175 - 51.175 9,512 9,860
605,275 657,077
$25 Par Value - Authorized 2,000,000 shares; none outstanding in 1994 and 1993
Total Preferred Stock (Subject to purchase or sinking funds) 51,946 55,344
Less: Current portion, including sinking fund requirements 2,418 2,504
Total Preferred Stock, Net (Subject to purchase or sinking funds) 49,528 2% 52,840 2%
44
December 31, 1994 1993
Long-Term Debt (Notes 3, 4 and 8): (Thousands of Dollars)
SCANA Corporation:
Bank Notes, due 1996 (6.44%, reset quarterly) 60,000 60,000
Medium-term Notes:
Year of
Series Maturity
5.76% 1998 20,000 20,000
7.17% 1999 42,400 42,400
6.60% 1999 30,000 30,000
6.15% 2000 20,000 20,000
6.51% 2003 20,000 20,000
South Carolina Electric & Gas Company:
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 -
7 1/8% 2013 150,000 150,000
7 1/2% 2023 150,000 150,000
7 5/8% 2023 100,000 100,000
First and Refunding Mortgage Bonds:
Year of
Series Maturity
4 7/8% 1995 16,000 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
7 1/4% 2002 30,000 30,000
9% 2006 145,000 145,000
8 7/8% 2021 155,000 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,660 6,760
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365
Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 -
Capitalized Lease Obligations, due 1991-1997 (various rates between
5 3/4% and 10%) 1,842 2,897
Installment Note Payable, due 1996 1,452 2,277
Department of Energy Decontamination and Decommissioning Obligation 3,922 4,634
South Carolina Generating Company, Inc.:
Berkeley County Pollution Control
Facilities Revenue Bonds, due 2014 (6.50%) 35,850 35,850
Note, 7.78%, due 2011 67,400 71,100
South Carolina Fuel Company, Inc.:
Nuclear and Fossil Fuel Liability 50,594 36,750
South Carolina Pipeline Corporation:
Notes, 6.72%, due 2013 23,750 25,000
Note, 9.27%, due 1991-1994 - 8,000
SCANA Development Corporation:
Notes, due 1994-2004 (various rates between 8.5% and 12.0%) - 1,770
Bank Loans, due 1994-1998 (various rates between 6% and 6.25%) 3,246 13,839
Total Long-Term Debt 1,580,601 1,464,762
Less - Current maturities, including sinking fund requirements 38,055 34,322
- Unamortized discount 4,922 6,041
Total Long-Term Debt, Net 1,537,624 51% 1,424,399 50%
Total Capitalization $3,023,617 100% $2,836,311 100%
See Notes to Consolidated Financial Statements.
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
SCANA Corporation (Company), a South Carolina corporation,
is a public utility holding company within the meaning of the
Public Utility Holding Company Act of 1935 but is exempt from
registration under such Act.
The accompanying Consolidated Financial Statements reflect
the consolidation of the accounts of the Company and its wholly
owned subsidiaries:
Regulated utilities
South Carolina Electric Gas Company (SCE&G)
South Carolina Fuel Company, Inc.
South Carolina Generating Company, Inc. (GENCO)
South Carolina Pipeline Corporation (Pipeline Corporation)
Nonregulated businesses
SCANA Petroleum Resources, Inc. (Petroleum Resources)
SCANA Hydrocarbons, Inc.
Suburban Propane Group, Inc.
MPX Systems, Inc. (MPX)
Primesouth, Inc.
ServiceCare, Inc.
SCANA Development Corporation
SCANA Capital Resources, Inc.
Investments in joint ventures in real estate and
telecommunications are reported using the equity method of
accounting. Significant intercompany balances and transactions
have been eliminated in consolidation.
In January 1994 the Company signed an agreement to sell
substantially all of the real estate assets of SCANA Development
Corporation to Liberty Properties Group, Inc. (Liberty) of
Greenville, South Carolina for $91.5 million. On March 4, 1994
the Company and Liberty amended the agreement to exclude certain
projects then under construction, and the sales price was reduced
to $49.6 million. The transaction was closed on May 27, 1994.
Certain other assets of SCANA Development Corporation are being
sold to other parties. These transactions did not have a
material impact on the Company's financial position or results of
operations.
B. System of Accounts
The accounting records of the Company's regulated
subsidiaries are maintained in accordance with the Uniform System
of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and as adopted by the Public Service Commission
of South Carolina (PSC).
46
C. Utility Plant
Utility plant is stated substantially at original cost. The
costs of additions, renewals and betterments to utility plant,
including direct labor, material and indirect charges for
engineering, supervision and an allowance for funds used during
construction, are added to utility plant accounts. The original
cost of utility property retired or otherwise disposed of is
removed from utility plant accounts and generally charged, along
with the cost of removal, less salvage, to accumulated
depreciation. The costs of repairs, replacements and renewals of
items of property determined to be less than a unit of property
are charged to maintenance expense.
SCE&G, operator of the V. C. Summer Nuclear Station (Summer
Station), and the South Carolina Public Service Authority (PSA)
are joint owners of Summer Station in the proportions of two-
thirds and one-third, respectively. The parties share the op-
erating costs and energy output of the plant in these
proportions. Each party, however, provides its own financing.
Plant in service related to SCE&G's portion of Summer Station
was approximately $923.1 million and $920.2 million as of
December 31, 1994 and 1993, respectively. Accumulated
depreciation associated with SCE&G's share of Summer Station was
approximately $297.9 million and $285.3 million as of December
31, 1994 and 1993, respectively. SCE&G's share of the direct
expenses associated with operating Summer Station is included in
"Other operation" and "Maintenance" expenses.
D. Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC), a
noncash item, reflects the period cost of capital devoted to
plant under construction. This accounting practice results in
the inclusion, as a component of construction cost, of the costs
of debt and equity capital dedicated to construction investment.
AFC is included in rate base investment and depreciated as a
component of plant cost in establishing rates for utility
services. The Company's regulated subsidiaries calculated AFC
using composite rates of 8.5%, 9.3% and 9.6% for 1994, 1993 and
1992, respectively. These rates do not exceed the maximum
allowable rate as calculated under FERC Order No. 561. Interest
on nuclear fuel in process and sulfur dioxide emission allowances
is capitalized at the actual interest amount.
E. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that
date, SCE&G ceased the deferral of carrying costs associated with
400 MW of electric generating capacity previously removed from
rate base and began amortizing the accumulated deferred carrying
costs on a straight-line basis over a ten-year period.
Amortization of deferred carrying costs, included in
"Depreciation and amortization," was approximately $4.2 million
for each of 1994, 1993 and 1992.
F. Revenue Recognition
Customers' meters are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the
accounting period in which the meters are read.
Fuel costs for electric generation are collected through the
fuel cost component in retail electric rates. The fuel cost
component contained in electric rates is established by the PSC
during semiannual fuel cost hearings. Any difference between
actual fuel costs and that contained in the fuel cost component
is deferred and included when determining the fuel cost component
during the next semiannual fuel cost hearing. SCE&G had
undercollected through the electric fuel cost component
approximately $3.5 million at December 31, 1994 and overcollected
approximately $9.2 million at December 31, 1993 which are
included in "Deferred Debits-Other" and "Deferred Credits-Other",
respectively.
47
Customers subject to the gas cost adjustment clause are billed
based on a fixed cost of gas determined by the PSC during annual
gas cost recovery hearings. Any difference between actual gas
cost and that contained in the rates is deferred and included
when establishing gas costs during the next annual gas cost
recovery hearing. At December 31, 1994 and 1993 the Company had
undercollected through the gas cost recovery procedure
approximately $16.3 million and $12.0 million, respectively,
which are included in "Deferred Debits-Other."
G. Depreciation, Depletion 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 as follows:
1994 1993 1992
SCE&G 3.01% 2.97% 3.00%
GENCO 2.70% 2.64% 2.63%
Pipeline Corporation 2.79% 2.62% 2.62%
Aggregate of Above 2.98% 2.92% 2.96%
Nuclear fuel amortization, which is included in "Fuel used
in electric generation" and is recovered through the fuel cost
component of SCE&G's rates, is recorded using the units-of-
production method. Provisions for amortization of nuclear fuel
include amounts necessary to satisfy obligations to the United
States Department of Energy under a contract for disposal of
spent nuclear fuel.
The acquisition adjustment relating to the purchase of
certain gas properties in 1982 is being amortized over a 40-year
period using the straight-line method.
Depreciation, depletion and amortization (DD&A) of the
capitalized costs of oil and gas producing properties is provided
for on the units-of-production basis. Units-of-production rates
are based on estimated proved reserves.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
The expenditures (on a before-tax basis) related to SCE&G's share
of decommissioning activities are currently estimated, in 2022
dollars assuming a 4.5% annual rate of inflation, to be $545.3
million including partial reclamation costs. SCE&G is providing
for its share of estimated decommissioning costs of Summer
Station over the life of Summer Station. SCE&G'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 and $2.5 million in 1994 and 1993,
respectively) are used to purchase insurance policies on the
lives of key Company personnel. Through the purchase of
insurance contracts, SCE&G 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 SCE&G to an
external trust fund in compliance with the financial assurance
requirements of the Nuclear Regulatory Commission. Management
intends for the fund, including earnings thereon, to provide for
all eventual decommissioning expenditures on an after-tax basis.
Thus, the trust's sources of decommissioning funds under the
COMReP program include investment components of life insurance
policy proceeds, return on investments, and the cash transfers
from SCE&G described above. SCE&G records its liability for
decommissioning costs in deferred credits.
48
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 financial
statements of electric utilities with nuclear generating
facilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting
for removal costs, including decommissioning. If the current
electric utility industry accounting practices for such
decommissioning are changed: (1) annual provisions for
decommissioning could increase, and (2) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction of decommissioning
expense.
In addition, pursuant to the National Energy Policy Act
passed by Congress in 1992, SCE&G has recorded a liability for
its estimated share of amounts required by the U.S. Department of
Energy for its decommissioning fund. SCE&G will recover the
costs associated with this liability, totaling $4.3 million at
December 31, 1994, through the fuel cost component of its rates;
accordingly, these amounts have been deferred and are included in
"Deferred Debits-Other" and "Long-Term Debt, Net."
I. Income Taxes
The Company and its subsidiaries file consolidated Federal
and State income tax returns. Income taxes are allocated to all
subsidiaries based on their contributions to consolidated taxable
income.
The Company adopted Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," effective
January 1, 1993. Prior years' financial statements have not been
restated. Deferred tax assets and liabilities were adjusted from
the amounts recorded at December 31, 1992 under prior standards
to the amounts required at January 1, 1993 under Statement No.
109 at currently enacted income tax rates. The adjustments were
charged or credited to regulatory assets or liabilities if the
Company expected to recover the resulting additional income tax
expense from, or pass through the resulting reductions in income
tax expense to, customers of the Company's regulated
subsidiaries; otherwise, they were charged or credited to income
tax expense. The cumulative effect of adopting Statement No. 109
on retained earnings as of January 1, 1993, as well as the effect
of adoption on net income for the year ended December 31, 1993,
was not material. At December 31, 1993 the combined effect of
adopting Statement No. 109 and adjusting deferred tax assets and
liabilities for the change in 1993 of the corporate Federal
income tax rate from 34% to 35% resulted in balances of $100.8
million in regulatory assets (included in "Deferred Debits-
Other") and $69.3 million in regulatory liabilities (included in
"Deferred Credits-Other") for the Company's regulated
subsidiaries.
In accordance with Statement No. 109, deferred tax assets
and liabilities are recorded for the tax effects of temporary
differences between the book basis and tax basis of assets and
liabilities at currently enacted tax rates. Deferred tax assets
and liabilities are adjusted for changes in such rates through
charges or credits to regulatory assets or liabilities if they
are expected to be recovered from, or passed through to,
customers of the Company's regulated subsidiaries; 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 of the Company's regulated subsidiaries.
Accumulated deferred income taxes were generally not adjusted for
changes in enacted tax rates.
49
J. Pension Expense
The Company has a noncontributory defined benefit pension
plan covering substantially all permanent employees. Benefits
are based on years of accredited service and the employee's
average annual base earnings received during the last three years
of employment. The Company's policy has been to fund pension
costs accrued to the extent permitted by the applicable Federal
income tax regulations as determined by an independent actuary.
Net periodic pension cost for the years ended December 31,
1994, 1993 and 1992 included the following components:
1994 1993 1992
(Thousands of Dollars)
Service cost--benefits earned during the period $ 8,684 $ 7,629 $ 7,174
Interest cost on projected benefit obligation 21,711 20,413 19,628
Adjustments:
Return on plan assets 2,365 (50,389) (28,607)
Net amortization and deferral (29,760) 25,936 8,096
Net periodic pension cost $ 3,000 $ 3,589 $ 6,291
The determination of net periodic pension cost is based upon
the following assumptions:
1994 1993 1992
Annual discount rate 7.25% 8.0% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 4.75% 5.5% 5.5%
The following table sets forth the funded status of the plan at December
31, 1994 and 1993:
1994 1993
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $205,364 $204,794
Nonvested benefit obligation 13,966 14,085
Accumulated benefit obligation $219,330 $218,879
Plan assets at fair value
(invested primarily in equity
and debt securities) $347,702 $351,648
Projected benefit obligation 246,318 295,718
Plan assets greater than
projected benefit obligation 101,384 55,930
Unrecognized net transition liability 11,307 10,713
Unrecognized prior service costs 9,374 9,294
Unrecognized net gain (102,284) (64,607)
Pension asset recognized in
Consolidated Balance Sheets $ 19,781 $ 11,330
50
The accumulated benefit obligation is based on the plan's
benefit formulas without considering expected future salary
increases. The following table sets forth the assumptions used
in determining the amounts shown above for the years 1994, 1993
and 1992.
1994 1993 1992
Annual discount rate used to determine
benefit obligations 8.0% 7.25% 8.0%
Assumed annual rate of future salary increases
for projected benefit obligation 2.5% 4.75% 5.5%
The change in the annual discount rate used to determine
benefit obligations from 7.25% to 8.0% and the change in the
expected salary increase rate from 4.75% to 2.5% as of December
31, 1994 decreased the projected benefit obligation and increased
the unrecognized net gain by approximately $67.7 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. The costs of postretirement benefits
other than pensions are accrued during the years the employees
render the service necessary to be eligible for the applicable
benefits. Prior to 1993, the Company expensed these benefits,
which are primarily health care, as claims were incurred. In its
June 1993 electric rate order the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. The Company expensed approximately $8.6 million and
$4.3 million, net of payments to current retirees, for the years
ended December 31, 1994 and 1993, respectively.
Net periodic postretirement benefit cost for the years ended
December 31, 1994 and 1993, included the following components:
1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 2,417 $ 1,908
Interest cost on accumulated postretirement benefit
obligation 6,644 5,502
Adjustments:
Return on plan assets - -
Amortization of unrecognized transition
obligation 3,344 3,344
Other net amortization and deferral 860 -
Net periodic postretirement benefit cost $13,265 $10,754
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1994 1993
Annual discount rate 7.25% 8.0%
Health care cost trend rate 11.25% 13.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 5.25% 6.0%
51
The following table sets forth the funded status of the plan at December 31, 1994 and 1993:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 59,174 $ 40,865
Other fully eligible participants 4,995 6,841
Other active participants 24,889 25,767
Accumulated postretirement benefit obligation 89,058 73,473
Plan assets at fair value - -
Plan assets less accumulated postretirement benefit
obligation (89,058) (73,473)
Unrecognized net transition liability 61,581 64,925
Unrecognized prior service costs 3,453 -
Unrecognized net loss 11,156 4,284
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(12,868) $ (4,264)
The accumulated postretirement benefit obligation is based
upon the plan's benefit provisions and the following assumptions:
1994 1993
Assumed health care cost trend rate used to
measure expected costs 12.0% 11.25%
Ultimate health care cost trend rate
(to be achieved in 2004) 6.0% 5.25%
Annual discount rate 8.0% 7.25%
Annual rate of salary increases 2.5% 4.75%
The effect of a one-percentage-point increase in the assumed
health care cost trend rate for each future year on the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for the year ended December 31,
1994 and the accumulated postretirement benefit obligation
as of December 31, 1994 would be to increase such amounts by
$210,000 and $3.3 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on
Reacquired Debt
Long-term debt premium, discount and expense are being
amortized as components of "Interest on long-term debt, net" over
the terms of the respective debt issues. Gains or losses on
reacquired debt that is refinanced are deferred and amortized
over the term of the replacement debt.
L. Environmental
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore, actual expenditures could differ
significantly from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have been deferred and are
being amortized and recovered through rates over a ten-year
period for electric operations and an eight-year period for gas
operations. Such deferred amounts totaled $20.2 million and
$19.6 million at December 31, 1994 and 1993, respectively, and
are included in "Deferred Debits-Other."
52
M. Oil and Gas
Oil and gas properties are accounted for using the
successful-efforts method. The costs of acquiring nonproducing
acreage, drilling successful exploration wells, and all
development costs are capitalized. The Company's net investment
in oil and gas properties is subject to a quarterly ceiling
limitation calculation that is based on the future net revenues
from forecasted production of proved oil and gas reserves valued
at current or contract prices. Carrying value of proved reserves
in excess of the ceiling limitation are expensed currently. The
Company's investments in nonproducing properties are evaluated
periodically, and if conditions warrant, an impairment reserve is
provided. Cost of that portion of undeveloped acreage likely to
be unproductive, based largely on historical experience, are
amortized over the period of exploration. Annual lease rentals
and exploration costs, including geological and geophysical costs
and exploratory dry-hole cost, are expensed as incurred.
N. Gas Futures Contracts
The Company sells gas futures and forward contracts,
purchases options, and enters into over-the-counter agreements to
hedge price risks for the majority of Petroleum Resources'
production. Gains and losses on the above are recognized
concurrently with the revenue from the associated gas sales.
O. Temporary Cash Investments
The Company considers temporary cash investments having
original maturities of three months or less to be cash
equivalents. Temporary cash investments are generally in the
form of commercial paper, certificates of deposit and repurchase
agreements.
P. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1994 presentation.
2. RATE MATTERS:
A. On October 27, 1994 the PSC issued an order approving
SCE&G'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, provides
for the recovery of approximately $16.2 million representing
substantially all site assessment and cleanup costs for SCE&G's
gas operations that had previously been deferred.
B. On June 7, 1993 the PSC issued an order on SCE&G's
pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually,
based on a test year. These rates were implemented in two phases
over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, based on a test year.
C. On September 14, 1992 the PSC issued an order granting
SCE&G a $.25 increase in transit fares from $.50 to $.75 in both
Columbia and Charleston, South Carolina; however, the PSC also
required $.40 fares for low income customers and denied SCE&G's
request to reduce the number of routes and frequency of
service. The new rates were placed into effect on October
5, 1992. SCE&G has appealed the PSC's order to the Circuit
Court.
53
D. Effective with the first billing cycle in December 1991,
SCE&G's gas rate schedules for its residential, small commercial
and small industrial customers have included a weather
normalization adjustment (WNA). The WNA minimizes fluctuations
in gas revenues due to abnormal weather conditions and is subject
to annual review by the PSC. The PSC order was based on a
return on common equity of 12.25%. On August 26, 1994, the PSC
ordered that the WNA be made permanent.
E. In May 1989 the PSC approved a volumetric and direct
billing method for Pipeline Corporation to recover take-or-pay
costs incurred from its interstate pipeline suppliers pursuant
to FERC-approved final and nonappealable settlements. In
December 1992 the Supreme Court approved Pipeline Corporation's
full recovery of the take-or-pay charges imposed by its suppliers
and treatment of these charges as a cost of gas. However, the
Supreme Court declared the PSC-approved "purchase deficiency"
methodology for recovery of these costs to be unlawful
retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. On April 30, 1994 the PSC
issued an order involving Pipeline Corporation's recovery of
take-or-pay cost incurred pursuant to FERC-approved settlements
with its upstream interstate pipeline supplier. This order
provided a mechanism for Pipeline Corporation to recover its
take-or-pay cost volumetrically over a period of approximate 30
months. SCE&G receives a credit for payments made prior to the
April 30 order which is netted against the current volumetric
surcharge. That net cost is recovered by SCE&G through its
purchased gas adjustment clause.
F. On August 8, 1990 the PSC issued an order, effective
November 1, 1990, approving changes in Pipeline Corporation's gas
rate design for sales for resale service and upholding the
"value-of-service" method of regulation for its direct industrial
service. Direct industrial customers seeking "cost-of-service"
based rates initiated two separate appeals to the Circuit Court,
which reversed and remanded to the PSC its August 8, 1990 order.
Pipeline Corporation appealed that decision to the Supreme Court
which, on January 10, 1994, reversed the two Circuit Court
decisions and reinstated the PSC Order. The Supreme Court held
that the industrial customer group's appeal was premature and
failed to exhaust administrative remedies. Additionally, the
Supreme Court interpreted the rate-making statutes of South
Carolina to give discretion to the PSC in selecting the
methodology to be used in setting rates for natural gas service.
G. On July 3, 1989 the PSC granted SCE&G approximately $21.9
million of a requested $27.2 million annual increase in retail
electric revenues based upon an allowed return on common equity
of 13.25%. The Consumer Advocate appealed the decision to the
Supreme Court which, on August 31, 1992, found that the evidence
in the record of that case did not support a return on common
equity higher than 13.0% and remanded to the PSC a portion of its
July 1989 order for a determination of the proper return on
common equity consistent with the Supreme Court's opinion. On
January 19, 1993 the PSC issued an order allowing a return on
common equity of 13.0%, approving a refund based on the
difference in rates created by the difference between the 13.0%
and the 13.25% return on common equity and making other
nonmaterial adjustments to the calculation of cost-of-service.
The total refund, before interest and income taxes, was
approximately $14.6 million and was charged against 1992
"Electric Revenues." The refund plus interest was made during
1993.
54
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including
the amounts due under the nuclear and fossil fuel agreement (see
Note 4), and sinking fund requirements for the years 1995 through
1999 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1995 $ 38,055 1998 $60,174
1996 147,248 1999 92,584
1997 38,306
Approximately $14.8 million of the portion of long-term debt
payable in 1995 may be satisfied by either deposit and
cancellation of bonds issued upon the basis of property additions
or bond retirement credits, or by deposit of cash with the
Trustee.
In January 1995 the Company arranged for an unsecured bank
loan of $60 million, due January 12, 1996 at an initial interest
rate of 6.44%, subject to reset quarterly at LIBOR plus ten basis
points. Proceeds from the loans were used to repay bank loans
totaling $60 million due January 13, 1995; accordingly, such
loans are included in long-term debt at December 31, 1994.
Substantially all utility plant and fuel inventories are
pledged as collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories are financed through the
issuance of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires July 31, 1996. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $75 million that may
be outstanding at any time.
Commercial paper outstanding totaled $50.6 million and $36.8
million at December 31, 1994 and 1993 at weighted average
interest rates of 6.06% and 3.47%, respectively.
5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not
Subject to Purchase or Sinking Funds):
The changes in "Common Stock," without par value, during
1994, 1993 and 1992 are summarized as
follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1991 40,784,327 $571,597
Issuance of common stock 3,126,304 127,406
Balance December 31, 1992 43,910,631 699,003
Issuance of common stock 2,708,826 127,662
Balance December 31, 1993 46,619,457 826,665
Issuance of common stock 1,398,053 60,105
Balance December 31, 1994 48,017,510 $886,770
55
The Restated Articles of Incorporation of the Company do not
limit the dividends that may be payable on its common stock.
However, the Restated Articles of Incorporation of SCE&G and the
Indenture underlying its First and Refunding Mortgage Bonds
contain provisions that may limit the payment of cash dividends
on its common stock. In addition, with respect to hydroelectric
projects, the Federal Power Act may require the appropriation of
a portion of the earnings therefrom. At December 31, 1994
approximately $13.2 million of retained earnings were restricted
as to payment of cash dividends on common stock.
Cash dividends on common stock were declared at an annual
rate per share of $2.82, $2.74 and $2.68 for 1994, 1993 and 1992,
respectively.
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, SCE&G 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. SCE&G 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.
The aggregate annual amounts of purchase fund or sinking fund
requirements for preferred stock for the years 1995 through 1999
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1995 $2,418 1998 $2,440
1996 2,482 1999 2,440
1997 2,440
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 1994, 1993 and 1992 are summarized as follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1991 998,404 $61,838
Shares Redeemed:
$100 par value (6,098) (610)
$50 par value (51,777) (2,589)
Balance December 31, 1992 940,529 58,639
Shares Redeemed:
$100 par value (7,374) (737)
$50 par value (51,187) (2,558)
Balance December 31, 1993 881,968 55,344
Shares Redeemed:
$100 par value (8,072) (807)
$50 par value (51,802) (2,591)
Balance December 31, 1994 822,094 $51,946
56
7. INCOME TAXES:
Total income tax expense for 1994, 1993 and 1992 is as follows:
1994 1993 1992
(Thousands of Dollars)
Current taxes:
Federal $62,033 $59,590 $67,240
State 13,178 6,409 8,146
Total current taxes 75,211 65,999 75,386
Deferred taxes, net:
Federal 10,242 23,219 (11,888)
State (86) 6,003 413
Total deferred taxes 10,156 29,222 (11,475)
Investment tax credits:
Amortization of amounts deferred (credit) (3,631) (3,659) (3,659)
Total income tax expense $81,736 $91,562 $60,252
The difference in actual income taxes and the income taxes
calculated from the application of the statutory Federal income
tax rate (35% for 1994 and 1993 and 34% for 1992) to pretax
income is reconciled as follows:
1994 1993 1992
(Thousands of Dollars)
Net income $151,199 $167,981 $117,590
Total income tax expense:
Charged to operating expenses 94,510 90,007 60,947
Charged (credited) to other income (12,774) 1,555 (695)
Preferred stock dividends 5,955 6,217 6,473
Total pretax income $238,890 $265,760 $184,315
Income taxes on above at statutory
Federal income tax rate $ 83,612 $ 93,016 $ 62,667
Increases (decreases) attributable to:
Allowance for funds used during
construction (excluding nuclear fuel) (2,862) (3,125) (1,868)
Deferred return on plant investment,
net of amortization 1,486 1,486 1,444
Depreciation differences 2,860 2,794 2,129
Amortization of investment tax credits (3,631) (3,659) (3,659)
State income taxes (less Federal income
tax effect) 8,510 8,068 5,649
Deferred income tax flowback at higher
than statutory rates (4,327) (4,411) (5,565)
Alternate fuel production tax credit (1,274) (1,373) (275)
Other differences, net (2,638) (1,234) (270)
Total income tax expense $ 81,736 $ 91,562 $ 60,252
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. The impact of this change
on the Company's financial position and results of operations was
not material.
57
The tax effects of significant temporary differences comprising
the Company's net deferred tax liability of $570.4 million at
December 31, 1994 and $559.6 million at December 31, 1993
determined in accordance with Statement No. 109 (see Note 1I) are
as follows:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 56,588 $ 58,839
Cycle billing 17,521 15,084
Nuclear operations expenses 206 4,908
Deferred compensation 5,513 5,315
Other post retirement benefits 3,187 1,631
Other 8,392 11,102
Total deferred tax assets 91,407 96,879
Deferred tax liabilities:
Property, plant and equipment (including
DD&A and basis differences) 625,636 619,859
Pension expense 9,022 6,266
Deferred fuel revenue 7,803 931
Reacquired debt 7,146 7,574
Other 12,197 21,814
Total deferred tax liabilities 661,804 656,444
Net deferred tax liability $570,397 $559,565
"Total deferred taxes" charged (credited) to income tax expense result
from timing differences in recognition of the following items (thousands of
dollars):
1992
Charged (credited) to expense:
Property, plant and equipment
(including DD&A and basis differences) $ 7,435
Deferred fuel revenue (2,958)
Property taxes 562
Cycle billing (1,321)
Take-or-pay contracts (1,118)
Nuclear refueling accrual (4,430)
Electric rate refund (6,571)
Injuries and damages (1,377)
Other, net (1,697)
Total deferred taxes $(11,475)
The Internal Revenue Service has examined and closed consolidated
Federal income tax returns of the Company through 1989 and is
currently examining the 1990, 1991 and 1992 Federal income tax
returns. No adjustments are currently proposed by the examining
agent. The Company 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.
58
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the
Company's financial instruments at December 31, 1994 and 1993
are as follows:
1994 1993
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Cash and temporary
cash investments $ 10,934 $ 10,934 $ 20,766 $ 20,766
Investments 24,858 27,099 5,312 15,235
Short-term borrowings 183,027 183,027 43,019 43,019
Total long-term debt 1,575,679 1,490,852 1,458,721 1,551,873
Total preferred stock
(subject to purchase
or sinking funds) 51,946 49,348 55,344 51,618
The information presented herein is based on pertinent
information available to the Company as of December 31, 1994
and 1993. Although the Company is not aware of any factors that
would significantly affect the estimated fair value amounts, such
financial instruments have not been comprehensively revalued
since December 31, 1994, and the current estimated fair value may
differ significantly from the estimated fair value at that date.
The following methods and assumptions were used to estimate the
fair value of the above classes of financial instruments:
Cash and temporary cash investments, including commercial
paper, repurchase agreements, treasury bills and notes are valued
at their carrying amount.
Fair values of investments and long-term debt are based on
quoted market prices for similar instruments, or for those
instruments for which there are no quoted market prices
available, fair values are based on net present value
calculations. Investments which are not considered to be
financial instruments (goodwill) have been excluded from the
carrying amount and estimated fair value. Settlement of long-
term debt may not be possible or may not be a prudent management
decision.
Short-term borrowings are valued at their carrying amount.
The fair value of preferred stock (subject to purchase or
sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in
an actual sale or settlement have not been taken into
consideration.
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its lines
of credit. Commercial paper borrowings are for 270 days or less.
Details of lines of credit and short-term borrowings at December
31, 1994, 1993 and 1992 and for the years then ended are as
follows:
1994 1993 1992
(Millions of Dollars)
Authorized lines of credit at year-end $479.1 $335.0 $288.9
Unused lines of credit at year-end $455.1 $308.0 $262.8
Short-term borrowings outstanding at
year-end:
Bank loans $ 71.1 $ 42.0 $ 41.1
Weighted average interest rate 6.50% 3.71% 4.49%
Commercial paper $111.2 $ 1.0 -
Weighted average interest rate 6.04% 3.35% -
59
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
SCE&G entered into a contract with Duke/Fluor Daniel in 1991
to design, engineer and build a 385 MW coal-fired electric
generating plant near Cope, South Carolina in Orangeburg County.
Construction of the plant began in November 1992 and is expected
to be complete in late 1995 with commercial operation beginning
in early 1996. The estimated cost of the Cope plant, excluding
financing costs and AFC but including an allowance for
escalation, is $450 million. In addition, the transmission lines
for interconnection with SCE&G's system are expected to cost $26
million.
Under the Duke/Fluor Daniel contract SCE&G must make
specified monthly minimum payments. These minimum payments do
not include amounts for inflation on a portion of the contract
which is subject to escalation (approximately 34% of the total
contract amount). The aggregate amount of such required minimum
payments remaining at December 31, 1994 is as follows (thousands
of dollars):
1995 $ 59,766
1996 5,603
Total $ 65,369
Through December 31, 1994 SCE&G had paid $310 million under the
contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with
public liability for a nuclear incident, currently establishes
the liability limit for third-party claims associated with any
nuclear incident at $8.9 billion. Each reactor licensee is
currently liable for up to $79.3 million per reactor owned for
each nuclear incident occurring at any reactor in the United
States, provided that not more than $10 million of the liability
per reactor would be assessed per year. SCE&G's maximum
assessment, based on its two-thirds ownership of Summer Station,
would be approximately $52.9 million per incident, but not more
than $6.7 million per year.
SCE&G currently maintains policies (for itself and on behalf
of the PSA) with Nuclear Electric Insurance Limited (NEIL) and
American Nuclear Insurers (ANI) providing combined property and
decontamination insurance coverage of $1.4 billion for any losses
in excess of $500 million pursuant to existing primary coverages
(with ANI) on Summer Station. SCE&G pays annual premiums and, in
addition, could be assessed a retroactive premium not to exceed 7
1/2 times its annual premium in the event of property damage loss
to any nuclear generating facilities covered by NEIL. Based on
the current annual premium, this retroactive premium would not
exceed $8.2 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and
expenses arising from a nuclear incident at Summer Station exceed
the policy limits of insurance, or to the extent such insurance
becomes unavailable in the future, and to the extent that SCE&G's
rates would not recover the cost of any purchased replacement
power, SCE&G will retain the risk of loss as a self-insurer.
SCE&G has no reason to anticipate a serious nuclear incident at
Summer Station. If such an incident were to occur, it could have
a materially adverse impact on the Company's financial position.
60
C. Environmental
As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore, actual expenditures could differ
significantly from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have been deferred and are
being amortized and recovered through rates over a ten-year
period for electric operations and an eight-year period for gas
operations.
In September 1992 the Environmental Protection Agency (EPA)
notified SCE&G, the City of Charleston and the Charleston Housing
Authority of their potential liability for the investigation and
cleanup of the Calhoun Park Area Site in Charleston, South
Carolina. This site originally encompassed approximately 18
acres and included properties which were the locations for
industrial operations, including a wood preserving (creosote)
plant and one of SCE&G's decommissioned manufactured gas plants.
The original scope of this investigation has been expanded to
approximately 30 acres, including adjacent properties owned by
the National Park Service and the City of Charleston, and private
properties. The site has not been placed on the National
Priority List, but may be added before cleanup is initiated. The
potentially responsible parties (PRP) have agreed with the EPA to
participate in an innovative approach to site investigation and
cleanup called "Superfund Accelerated Cleanup Model," allowing
the pre-cleanup site investigations process to be compressed
significantly. The PRPs have negotiated an administrative order
by consent for the conduct of a Remedial
Investigation/Feasibility
Study (RI/FS) and a corresponding Scope of Work. Actual field
work began November 1, 1993 after final approval and
authorization was granted by EPA. SCE&G 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 SCE&G
that it considers SCE&G 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.
SCE&G believes it has meritorious defenses against this claim and
does not expect its resolution to have a material impact on its
financial position or results of operations.
D. Emission Allowances
The Company has entered into an agreement with a broker of
sulfur dioxide emission allowances to purchase $6.8 million of
allowances at a fixed price during 1995.
E. Personal Communication Services licenses
MPX is pursuing Personal Communication Services licenses for
wireless communications in the Southeast through a joint venture.
A $40 million construction loan obtained by the joint venture has
been guaranteed by SCANA Corporation.
F. Oil and Gas Forward Contracts
In an effort to limit exposure to changing natural gas
prices and to avoid a write-down resulting from the application
of the ceiling test (see Note 1M) at December 31, 1994, in
January 1995 the Company entered into a series of forward
contracts relating to natural gas production. These forward
contracts have the effect of stabilizing the price that the
Company will receive on approximately sixty percent of its
forecasted natural gas production for the years 1995-2001. The
forward contracts are at an average price of $1.88 per dekatherm.
61
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1994, 1993 and 1992 and for the years
then ended is as follows:
1994
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $975,388 $342,672 $ 4,002 $1,322,062
Operating expenses,
excluding depreciation
and amortization 640,528 292,227 10,577 943,332
Depreciation and
amortization 102,647 16,304 226 119,177
Total operating expenses 743,175 308,531 10,803 1,062,509
Operating income (loss) $232,213 $ 34,141 $ (6,801) 259,553
Add - Other income, net 5,998
Less - Interest charges 108,397
- Preferred stock dividends 5,955
Net income $ 151,199
Capital expenditures:
Identifiable $364,007 $ 20,079 $ 347 $ 384,433
Utilized for overall Company operations 20,167
Total $ 404,600
Identifiable assets at
December 31, 1994:
Utility plant, net $2,897,954 $315,746 $ 1,791 $3,215,491
Inventories 98,669 17,026 495 116,190
Total $2,996,623 $332,772 $ 2,286 3,331,681
Other assets 1,061,447
Total assets $4,393,128
62
1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,121 $320,195 $ 3,851 $1,264,167
Operating expenses,
excluding depreciation
and amortization 621,339 274,936 9,737 906,012
Depreciation and
amortization 97,849 14,820 175 112,844
Total operating expenses 719,188 289,756 9,912 1,018,856
Operating income (loss) $ 220,933 $ 30,439 $(6,061) 245,311
Add - Other income, net 30,076
Less - Interest charges 101,189
- Preferred stock dividends 6,217
Net income $ 167,981
Capital expenditures:
Identifiable $ 279,082 $ 28,761 $ 604 $ 308,447
Utilized for overall Company operations 13,934
Total $ 322,381
Identifiable assets at
December 31, 1993:
Utility plant, net $2,628,374 $312,437 $ 1,673 $2,942,484
Inventories 77,805 22,019 463 100,287
Total $2,706,179 $334,456 $ 2,136 3,042,771
Other assets 997,755
Total assets $4,040,526
63
1992
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 829,477 $305,275 $ 3,623 $1,138,375
Operating expenses,
excluding depreciation
and amortization 554,897 256,178 9,205 820,280
Depreciation and
amortization 93,978 14,174 163 108,315
Total operating expenses 648,875 270,352 9,368 928,595
Operating income (loss) $ 180,602 $ 34,923 $(5,745) 209,780
Add - Other income, net 11,883
Less - Interest charges 97,600
- Preferred stock dividends 6,473
Net income $ 117,590
Capital expenditures:
Identifiable $ 234,918 $ 33,495 $ 346 $ 268,759
Utilized for overall Company operations 8,877
Total $ 277,636
Identifiable assets at
December 31, 1992:
Utility plant, net $2,456,691 $299,591 $ 1,240 $2,757,522
Inventories 82,717 8,155 481 91,353
Total $2,539,408 $307,746 $ 1,721 2,848,875
Other assets 708,846
Total assets $3,557,721
64
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1994
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues (000) $347,309 $296,046 $361,329 $317,378 $1,322,062
Operating
income (000) 69,398 50,048 86,708 53,399 259,553
Net income (000) 50,124 29,167 49,690 22,218 151,199
Earnings per weighted
average share of
common stock
as reported 1.07 .62 1.04 .46 3.19
1993
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues (000) $321,840 $280,382 $359,453 $302,492 $1,264,167
Operating
income (000) 63,714 45,370 84,638 51,589 245,311
Net income (000) 45,110 26,909 64,427 31,535 167,981
Earnings per weighted
average share of
common stock
as reported 1.02 .61 1.41 .68 3.72
65
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable
PART III
The information required by Item 10, "Directors and
Executive Officers of the Registrant," with respect to executive
officers is, pursuant to General Instruction G(3) to Form 10-K,
set forth in Part I of this Form 10-K under the heading
"Executive Officers of the Registrant" on page 25 herein. The
other information required by Item 10, as well as that called for
by Item 11, "Executive Compensation," Item 12, "Security
Ownership of Certain Beneficial Owners and Management" and Item
13, "Certain Relationships and Related Transactions" is
incorporated herein by reference to the captions "Election of
Directors - Proposal 1," "Security Ownership of Certain
Beneficial Owners and Management," "Compensation of Directors,"
Compensation Committee Interlocks and Insider Participation,"
"Executive Compensation," "Description of Plans," and "Compliance
with Section 16(a) of the Securities Exchange Act of 1934" in the
Company's 1995 definitive proxy statement which will be filed
with the SEC pursuant to Regulation 14A, promulgated under the
Securities Exchange Act of 1934.
Notwithstanding anything to the contrary set forth in any of
the Company's previous filings under the Securities Act of 1933,
as amended, or the Securities Exchange Act of 1934, as amended,
that might incorporate by reference future filings, including
this Annual Report on Form 10-K, in whole or in part, the Report
of the Management Development and Corporate Performance Committee
and the Long-term Compensation Committee on Executive
Compensation and the Performance Graph included in the Company's
1995 definitive proxy statement shall not be incorporated by
reference into any such filings.
66
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) Documents filed as a part of this report:
1. Financial Statements and Schedules: See Table of Contents of
Consolidated Financial Statements and Supplementary Financial
Data on page 39.
2. Exhibits:
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 SEC and which are designated by reference to their
exhibit numbers in prior filings are incorporated herein by
reference and made a part hereof.
Pursuant to Rule 15d-21 promulgated under the Securities Exchange
Act of 1934, the annual reports for the Company's employee stock
purchase plan and employee stock ownership plan will be furnished
under cover of Form 10-K/A to the Commission when the information
becomes available.
As permitted under Item 601(b)(4)(iii), instruments defining the
rights of holders of long-term debt of less than 10 percent of
the total consolidated assets of the Company and its
subsidiaries, have been omitted and the Company agrees to furnish
a copy of such instruments to the Commission upon request.
Reports on Form 8-K
None
67
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) SCANA CORPORATION
BY (SIGNATURE) s/L. M. Gressette, Jr.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board, Chief
Executive Officer, President and Director
DATE February 14, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
(i) Principal executive officer:
BY (SIGNATURE) s/L. M. Gressette, Jr.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board, Chief
Executive Officer, President and Director
DATE February 14, 1995
(ii) Principal financial and accounting officer:
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Executive Vice President, Controller,
Chief Financial Officer and Director
DATE February 14, 1995
BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 14, 1995
BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 14, 1995
BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 14, 1995
BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 14, 1995
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 14, 1995
68
BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 14, 1995
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 14, 1995
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 14, 1995
BY (SIGNATURE) s/B. D. Kenyon
(NAME AND TITLE) B. D. Kenyon, Director
DATE February 14, 1995
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 14, 1995
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 14, 1995
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 14, 1995
BY (SIGNATURE) s/E. C. Wall, Jr.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 14, 1995
69