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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1998
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(A South Carolina Corporation)
1426 Main Street
Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
(A South Carolina Corporation)
1426 Main Street
Columbia, South Carolina 29201
(803) 217-9000
Securities registered pursuant to Section 12(b) of the Act:
Each of the following classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.
Title of each class Registrant
Common Stock, without par value SCANA Corporation
5% Cumulative Preferred Stock South Carolina Electric & Gas Company
par value $50 per share
7.55%Trust Preferred Securities, Series A liquidation value
$25 per Trust
Preferred Security
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Securities registered pursuant to Section 12(g) of the Act: None
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. ( )
The aggregate market value of voting stock held by non-affiliates of
SCANA Corporation was $2,433,956,641 at February 26, 1999. South Carolina
Electric & Gas Company is a wholly-owned subsidiary of SCANA Corporation and has
no voting stock other than its common stock. At February 26, 1999, there were
issued and outstanding 40,296,147 Common Shares, $4.50 par value, of South
Carolina Electric & Gas Company.
Documents incorporated by reference: Specified sections of SCANA
Corporation's 1999 Proxy Statement, dated March 15, 1999, in connection with its
1999 Annual Meeting of Stockholders, are incorporated by reference in Part III
hereof.
This combined Form 10-K is separately filed by SCANA Corporation and South
Carolina Electric & Gas Company. Information contained herein relating to SCANA
Corporation or any of its direct or indirect subsidiaries other than South
Carolina Electric & Gas Company is provided solely by SCANA Corporation and
shall be deemed not included in the Form 10-K of South Carolina Electric & Gas
Company.
TABLE OF CONTENTS
Page
DEFINITIONS 4
PART I
Item 1. Business 5
Item 2. Properties 17
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of Security Holders 19
Corporate Structure 20
Executive Officers of SCANA Corporation 21
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters 22
Item 6. Selected Financial Data 23
SCANA Corporation Financial Section 25
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 39
Item 8. Financial Statements and Supplementary Data 40
South Carolina Electric & Gas Company Financial Section 68
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 69
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 78
Item 8. Financial Statements and Supplementary Data 78
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 103
PART III
Item 10. Directors and Executive Officers of the Registrants 104
Item 11. Executive Compensation 108
Item 12. Security Ownership of Certain Beneficial Owners and Management 114
Item 13. Certain Relationships and Related Transactions 114
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 115
SIGNATURES 116
DEFINITIONS
The following abbreviations used in the text have the meanings set forth below
unless the context requires otherwise:
TERM MEANING
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, unless
otherwise specified
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
Energy Marketing............ SCANA Energy Marketing, Inc.
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.
Investor Plus Plan.......... SCANA Corporation Investor Plus Plan
KVA......................... Kilovolt-ampere
KW.......................... Kilowatt
KWH......................... Kilowatt-hour
LLC......................... Limited Liability Company
LNG......................... Liquefied Natural Gas
MCF......................... Thousand Cubic Feet
Mhz......................... Megahertz
MMCF........................ Million Cubic Feet
MW.......................... Megawatt
NEPA........................ National Energy Policy Act of 1992
NRC......................... United States Nuclear Regulatory Commission
PCS......................... Personal Communications Service
Petroleum Resources......... SCANA Petroleum Resources, Inc.
Pipeline Corporation........ South Carolina Pipeline Corporation
PRP......................... Potentially Responsible Party
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935,
as amended
SCI......................... SCANA Communications, Inc.
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
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipeline Corporation
Williams Station............ A. M. Williams Coal-Fired, Electric Generating
Station Owned by GENCO
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 holds, directly or indirectly, all of the capital stock of
each of its subsidiaries except for the preferred stock of SCE&G, the preferred
securities of SCE&G Trust I and 30% of the common stock of an indirect
subsidiary. SCANA and its subsidiaries had 4,697 full-time, permanent employees
as of December 31, 1998 as compared to 4,545 full-time, permanent employees as
of December 31, 1997. SCE&G was incorporated under the laws of South Carolina in
1924, and is an operating public utility.
Segments of Business
SCANA neither owns nor operates any physical properties. It has thirteen
direct, wholly owned subsidiaries which are engaged in the functionally distinct
operations described below. It also has investments in two LLCs, one of which is
building and will operate a cogeneration facility in Charleston, South Carolina,
and the other of which is constructing a lime production facility.
Regulated Utilities
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 area of Columbia, 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.
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 31 of the
46 counties in South Carolina and covers more than 21,000 square miles. The
total population of the counties representing the combined service area is
approximately 2.3 million.
Predominant industries in the areas served by SCE&G include: synthetic
fibers; chemicals ; fiberglass ; paper and wood; metal fabrication; stone, clay
and sand mining and processing; and textile.
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 40 counties throughout South Carolina. Pipeline
Corporation owns LNG liquefaction and storage facilities. Pipeline Corporation,
through a wholly owned subsidiary, owns and operates a 62-mile, six-inch propane
pipeline that connects the SCANA Propane Storage, Inc. propane storage facility
with Dixie Pipeline Company's system, which traverses central South Carolina. 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.
Nonregulated Businesses
Energy Marketing markets electricity, natural gas and other light
hydrocarbons primarily in the Southeast. In addition, Energy Marketing markets
natural gas in Georgia's deregulated natural gas market. Energy Marketing also
provides energy-related risk management services to producers and consumers.
SCANA Propane Gas, Inc. purchases, delivers and sells propane within the
Southeast.
SCANA Propane Storage, Inc. owns and operates a 60 million gallon
underground propane storage facility near York, South Carolina and leases cavern
storage space to industries, utilities and others.
SCI owns and operates a 500 mile fiber optics telecommunications network
in South Carolina as well as an 800 Mhz radio service network within the state.
In addition, SCI provides tower site construction, management and rental
services in South Carolina and Georgia. SCI also has investments in Powertel,
Inc., ITC Holding Company, Inc., ITC^DeltaCom, Inc., and Knology Holdings, Inc.,
which are companies providing telecommunications services in the southeastern
United States.
ServiceCare, Inc. is engaged in providing energy-related products and
services beyond the energy meter. Its primary businesses are providing
homeowners with service contracts on their home appliances and home security
monitoring.
Primesouth, Inc. is engaged in power plant management and maintenance
services.
SCANA Resources, Inc. conducts energy-related businesses and services.
Information with respect to major segments of business for the years
ended December 31, 1998, 1997 and 1996 is contained in Management's Discussion
and Analysis and in Note 11 of the Notes to Consolidated Financial Statements of
SCANA or SCE&G. All such information is incorporated herein by reference.
Competition
The electric utility industry continues a major transition that is
resulting in expanded market competition and less regulation. Deregulation of
electric wholesale and retail markets is creating 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. Legislative initiatives at
the Federal and state levels are being considered and, if enacted, could mandate
market deregulation. The pace of deregulation, future prices of electricity, and
the regulatory actions which may be taken by the PSC and the FERC in response to
the changing environment cannot be predicted. However, the FERC, in issuing
Order 888 in April 1996, has accelerated competition among electric utilities by
providing for open access to wholesale transmission service. Order 888 requires
utilities under FERC jurisdiction that own, control or operate transmission
lines to file nondiscriminatory open access tariffs that offer to others the
same transmission service they provide themselves. The FERC has also permitted
utilities to seek recovery of wholesale stranded costs from departing customers
by direct assignment. Approximately two percent of the Company's electric
revenue is under FERC jurisdiction for the purpose of setting rates for
wholesale service. Legislation is pending in South Carolina that would
deregulate the state's retail electric market and enable customers to choose
their supplier of electricity. The Company is not able to predict whether the
legislation will be enacted and, if it is, the conditions it will impose on
utilities that currently operate in the state and future market participants.
The Company is aggressively pursuing actions to position itself
strategically for the transformed environment. The Company's entry into the
newly deregulated retail natural gas market in Georgia is designed in part to
provide a potential market for any future deregulated electric industry. (For
additional discussion see Georgia Retail Gas Market in the Competition section
of Management's Discussion and Analysis for the Company.) In addition, SCE&G has
undertaken a variety of initiatives, including reductions in staffing levels and
the accelerated recovery of its electric regulatory assets. SCE&G has also
established open access transmission tariffs and is selling bulk power to
wholesale customers at market-based rates. A significant new management
information system was implemented in 1998, and a new customer information
system will be fully implemented in the first half of 1999. Marketing of
services to commercial and industrial customers has been increased
significantly. SCE&G has obtained long-term power supply contracts with a
significant portion of its industrial customers. The Company believes that these
actions as well as numerous others that have been and will be taken demonstrate
its commitment to succeed in the new operating environment to come.
Regulated public utilities are allowed to record as assets some costs
that would be expensed by other enterprises. If deregulation or other changes in
the regulatory environment occur, the Company may no longer be eligible to apply
this accounting treatment and may be required to eliminate such regulatory
assets from its balance sheet. Although the potential effects of deregulation
cannot be determined at present, discontinuation of the accounting treatment
could have a material adverse effect on the Company's results of operations in
the period that a write-off would be required. It is expected that cash flows
and the financial position of the Company would not be materially affected by
the discontinuation of the accounting treatment. In addition, the Company's
generation assets are exposed to considerable financial risks in a deregulated
electric market. If market prices for electric generation do not produce
adequate revenue streams and the enabling legislation or regulatory actions do
not provide for recovery of the resulting stranded costs, the Company could be
required to write down its investment in these assets. The Company cannot
predict whether any write-downs will be necessary and, if they are, the extent
to which they would adversely affect the Company's results of operations in the
period in which they are recorded.
Capital Requirements and Financing Program
Capital Requirements
The Company's cash requirements arise primarily from SCE&G's operational
needs, SCE&G's construction program and the need to fund the activities or
investments of SCANA's nonregulated subsidiaries. The ability of SCANA'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 continue their ongoing construction programs, it may be 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 and other regulatory relief, if
requested.
For a discussion of the impact of various rate matters on capital
requirements, see Regulatory Matters in the Liquidity and Capital Resources
section of Management's Discussion and Analysis for the Company and SCE&G.
During 1999 the Company is expected to meet its capital requirements
principally through internally generated funds (approximately 51%, after payment
of dividends) 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 current estimates of its cash requirements for construction
and nuclear fuel expenditures, which are subject to continuing review and
adjustment, for 1999 and the two-year period 2000-2001 are as follows:
Type of Facilities 2000-2001 1999
(Millions of Dollars)
SCE&G:
Electric Plant:
Generation $119 $89
Transmission 39 23
Distribution 137 71
Other 19 11
Nuclear Fuel 57 5
Gas 31 21
Common 29 26
Other 2 1
---- ----
Total 433 247
Other Companies Combined 98 66
---- ----
Total $531 $313
==== ====
The above estimates exclude AFC.
During 1998 SCE&G and GENCO expended approximately $36.2 million and
$10.7 million, respectively, as part of a program to extend the operating lives
of certain non-nuclear generating facilities. Additional improvements to be made
under the program during 1999, included in the table above, are estimated to
cost approximately $42.1 million and $8 million, respectively.
In addition to the capital requirements for 1999 described above, the
Company and SCE&G will require approximately $107.0 million and $29.6 million,
respectively, to refund and retire outstanding securities and obligations. For
the years 2000-2003, the Company has an aggregate of $555.3 million of long-term
debt maturing, which includes an aggregate of $360.4 million for SCE&G and $2.2
million of purchase or sinking fund requirements for SCE&G's preferred stock.
SCE&G's long term debt maturities for the years 2000-2003 include approximately
$79.9 million for sinking fund requirements, of which $73.9 million may be
satisfied by deposit and cancellation of bonds issued upon the basis of property
additions or bond retirement credits.
SCANA and Westvaco each own a 50% interest in Cogen South LLC (Cogen).
Cogen was formed to build and operate a cogeneration facility at Westvaco's
Kraft Division Paper Mill in North Charleston, South Carolina. Construction of
the facility began in September 1996 and is in the final stages. Construction
financing of approximately $170 million, was provided to Cogen by banks. On
December 30, 1998, SCANA provided a capital contribution of approximately $15.5
million to Cogen. On September 10, 1998, the contractor in charge of
construction filed suit in Circuit Court seeking approximately $51 million from
Cogen, alleging that construction cost overruns were incurred, and that the
construction contract provides for recovery of these costs. In addition to
Cogen, Westvaco, SCE&G and SCANA were also named in the suit. SCANA and the
other defendants believe the suit is without merit and are mounting an
appropriate defense. SCANA does not believe that the resolution of this issue
will have a material impact on its results of operations, cash flows or
financial position.
Financing Program
SCANA 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 subsidiaries, to reduce short-term debt incurred in connection
therewith or for general corporate purposes. At December 31, 1998, SCANA had
registered with the SEC and available for issuance $200.0 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 twelve
consecutive months out of the fifteen months prior to the month of issuance are
at least twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1998 the Bond Ratio
was 5.30. The issuance of additional Class A Bonds also is restricted to an
additional principal amount equal to (i) 60% of unfunded net property additions
(which unfunded net property additions totaled approximately $396 million at
December 31, 1998), (ii) retirements of Class A Bonds (which retirement credits
totaled $100.3 million at December 31, 1998), and (iii) cash on deposit with the
Trustee.
SCE&G has a bond indenture dated April 1, 1993 (New Mortgage) covering
substantially all of its electric properties under which its future
mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the
New Mortgage on the basis of a like principal amount of Class A Bonds issued
under the Old Mortgage which have been deposited with the Trustee of the New
Mortgage (of which $315 million were available for such purpose at December 31,
1998), until such time as two-thirds of all Class A Bonds are held by the
Trustee. Thereafter, the Old Mortgage may be amended to allow New Bonds to be
issuable on the basis of property additions in a principal amount equal to 70%
of the original cost of electric and common plant properties (compared to 60% of
value for Class A Bonds under the Old Mortgage), cash deposited with the
Trustee, and retirement of New Bonds. New Bonds will be issuable under the New
Mortgage only if adjusted net earnings (as therein defined) for twelve
consecutive months out of the eighteen months immediately preceding the month of
issuance are at least twice the annual interest requirements on all outstanding
bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond
Ratio). For the year ended December 31, 1998 the New Bond Ratio was 6.72.
SCE&G expects in 1999 to amend the Old Mortgage to conform certain of its
provisions to those of the New Mortgage, including (i) the elimination of the
maintenance and replacement fund and the utilization of unfunded net property
additions previously applied in satisfaction thereof as a basis for the issuance
of bonds; (ii) the issuance of bonds in a principal amount equal to 70% of
unfunded net property additions instead of 60%; and (iii) the conformance of the
interest coverage requirements for the issuance of bonds to those of the New
Mortgage.
The following additional financing transactions have occurred since
December 31, 1997:
o On January 13, 1998 SCANA issued $60 million of medium-term notes due
January 13, 2003 at an interest rate of 6.05%. These funds were used to
refinance unsecured bank loans in a like total amount.
o On July 8, 1998, SCANA issued $75 million of medium-term notes due on July
8, 2003 at an annual interest rate of 6.25%. These funds were used to
finance an additional investment of $75 million in Powertel.
o On October 23, 1998, SCANA issued $115 million of medium-term notes due on
October 23, 2008 at an annual interest rate of 5.81%. These funds were used
to reduce short-term debt.
o On October 29, 1998, SCANA's shelf registration statement filed with the
SEC became effective, providing for the issuance of up to an additional
$200 million in medium-term notes.
o On November 2, 1998, SCE&G redeemed, prior to maturity, all $30 million
principal amount outstanding of its 7.25% Series First and Refunding
Mortgage Bonds due January 1, 2002.
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; however,
no such consent is 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 $250 million of unsecured promissory notes or commercial paper with
maturity dates of twelve months or less but not later than December 31, 2001.
GENCO has not sought such authorization.
At December 31, 1998 SCE&G had $285 million of authorized lines of credit
which includes credit agreements for a maximum of $250 million to support the
issuance of commercial paper. Unused lines of credit at December 31, 1998
totaled $285 million. SCE&G's commercial paper outstanding at December 31, 1998
and 1997 was $125.2 million and $13.3 million, respectively. See "Fuel Financing
Agreements" for a discussion of Fuel Company's credit agreement.
SCE&G's Restated Articles of Incorporation prohibit issuance of
additional shares of preferred stock without the consent of the preferred
stockholders unless net earnings (as defined therein) for the twelve consecutive
months immediately preceding the month of issuance are at least one and one-half
times the aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended December 31, 1998 the
Preferred Stock Ratio was 2.27.
On January 26, 1998 an additional 3,000,000 shares of SCANA common stock
were registered for sale under the SPSP. During 1998, shares for the SPSP and
the Investor Plus Plan were purchased on the open market.
The Company's ratios of earnings to fixed charges (SEC method) were 3.75,
3.65, 3.60, 3.00 and 2.55 for the years ended December 31, 1998, 1997, 1996,
1995 and 1994, respectively. For SCE&G these ratios were 4.52, 3.85, 3.80, 3.41
and 3.46 for the same periods.
The Company expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the next twelve months and
for the foreseeable future.
Fuel Financing Agreements
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 fuels. To finance nuclear and fossil fuels and sulfur dioxide emission
allowances, Fuel Company issues, from time to time, commercial paper which is
supported, up to $125 million, by an irrevocable revolving credit agreement
which expires December 19, 2000. Accordingly, the amounts outstanding have been
included in long-term debt. This commercial paper and amounts outstanding under
the revolving credit agreement, if any, are guaranteed by SCE&G. The full amount
of the credit agreement was available at December 31, 1998. At December 31, 1998
commercial paper outstanding was approximately $66.0 million at a weighted
average interest rate of 5.45%. (See Note 4 of Notes to Consolidated Financial
Statements for the Company and for SCE&G.)
Electric Operations
Electric Sales
In 1998 residential sales of electricity accounted for 42% of electric
sales revenues; commercial sales 30%; industrial sales 19%; sales for resale 3%;
and all other 6%. The Company's KWH sales by classification for the years ended
December 31, 1998 and 1997 are as follows:
Sales
KWH (Millions)
Classification 1998 1997 %Change
Residential 6,324 5,647 11.98
Commercial 5,899 5,321 10.87
Industrial 5,824 5,434 7.18
Sale for resale 1,125 1,060 6.17
Other 536 506 5.90
Total Territorial 19,708 17,968 9.68
Negotiated Market
Sales Tariff 1,495 884 69.08
Total 21,203 18,852 12.47
Sales for resale includes electricity furnished for resale to three
municipalities and two electric cooperatives. One electric cooperative has
notified SCE&G of its intent to terminate in the year 2000 its wholesale power
contract with SCE&G and bid out its electric requirements. Sales under the
Negotiated Market Sales Tariff during 1998 include sales to 34 investor-owned
utilities, three electric cooperatives, one municipality and four federal/state
electric agencies. During 1997, sales under the Negotiated Market Sales Tariff
included sales to 28 investor-owned utilities, three electric cooperatives, two
municipalities and three federal/state electric agencies.
The electric sales volume from residential sales increased for 1998
primarily as a result of warmer weather. During 1998 SCE&G recorded a net
increase of 13,542 customers, increasing its total customers to 517,447. The
all-time peak demand of 3,935 MW was set on July 9, 1998.
Electric Interconnections
SCE&G purchases all of the electric generation of Williams Station,
owned by GENCO, under a Unit Power Sales Agreement which has been approved by
the FERC. Williams Station has a generating capacity of 580 MW.
SCE&G's transmission system is part of the interconnected grid
extending over a large part of the southern and eastern portions of the nation.
SCE&G, Virginia Power Company, Duke Power Company, Carolina Power & Light
Company, Yadkin, Incorporated and Santee Cooper (formerly The South Carolina
Public Service Authority) are members of the Virginia-Carolinas Reliability
Group, one of the several geographic divisions within the Southeastern Electric
Reliability Council. This Council provides for coordinated planning for
reliability among bulk power systems in the Southeast. 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 1996-1998.
1998 1997 1996
---- ---- ----
Nuclear:
Per million BTU $ .46 $ .47 $ .47
Coal:
SCE&G
Per ton $38.19 $38.22 $39.27
Per million BTU 1.50 1.54 1.55
GENCO:
Per ton $41.67 $44.49 $41.66
Per million BTU 1.63 1.61 1.62
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.49 $ 1.52 $ 1.52
Fuel Supply
The following table shows the sources and approximate percentages of
the Company's total KWH generation by each category of fuel for the years
1996-1998 and the estimates for 1999 and 2000.
Percent of Total KWH Generated
Estimated Actual
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Coal 73% 73% 69% 71% 71%
Nuclear 22 22 25 24 24
Hydro 5 5 5 5 5
Natural Gas & Oil - - 1 - -
--- --- --- ---- ---
100% 100% 100% 100% 100%
=== === === === ===
Coal is used at all five of SCE&G's fossil fuel-fired plants and
GENCO's Williams Station. Unit train deliveries are used at all of these plants
and truck deliveries are used at three of these plants. On December 31, 1998
SCE&G had approximately a 68-day supply of coal in inventory and GENCO had
approximately an 83-day supply.
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 existing contracts. Contracts for the purchase of coal
represent 86.6% of estimated requirements for 1999 (approximately 6.1 million
tons).
Contract coal is purchased from nine suppliers located in eastern
Kentucky, Tennessee and southwest Virginia. Contract commitments, which expire
at various times from 1999 through 2006, approximate 5.3 million tons annually.
Sulfur restrictions on the contract coal range from .75% to 2%.
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 is unaware that any more stringent sulfur content
requirements for existing plants are contemplated at the State level by DHEC.
However, the Company will be required to meet the more stringent Federal
emissions standards established by the Clean Air Act (see "Environmental
Matters").
SCE&G has adequate supplies of uranium or enriched uranium product
under contract to manufacture nuclear fuel for Summer Station through 2005. The
following table summarizes all contract commitments for the stages of nuclear
fuel assemblies:
Remaining Expiration
Commitment Contractor Regions (1) Date
- ---------- ---------- ----------- ----
Enrichment United States Enrichment Corporation(2) 14-18 2005
Fabrication Westinghouse Electric Corporation 14-21 2009
(1) A region represents approximately one-third to one-half of the nuclear
core in the reactor at any one time. Region 14 will be loaded in 1999.
(2) Contract provisions for the delivery of enriched uranium product encompass
supply, conversion and enrichment services.
SCE&G has on-site spent nuclear fuel storage capability until at least
2009 and expects to be able to expand its storage capacity to accommodate the
spent fuel output for the life of the plant through rod consolidation, dry cask
storage or other technology as it becomes available. In addition, there is
sufficient on-site storage capacity over the life of Summer Station to permit
storage of the entire reactor core in the event that complete unloading should
become desirable or necessary for any reason. (See "Nuclear Fuel Disposal" under
"Environmental Matters" for information regarding the contract with the DOE for
disposal of spent fuel.)
Summer Station will conduct a refueling outage in April 1999 which is
expected to last approximately 30 days.
Decommissioning
Decommissioning of Summer Station is presently scheduled to commence
when the operating license expires in the year 2022. Based on a 1991 study, the
expenditures (on a before-tax basis) related to SCE&G's share of decommissioning
activities were estimated to be approximately $200.0 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 in each of
1998 and 1997) are used to pay premiums on insurance policies on the lives of
certain Company personnel. SCE&G is the beneficiary of these policies. Through
these insurance contracts, SCE&G is able to take advantage of income tax
benefits and accrue earnings on the fund on a tax-deferred basis. 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 NRC.
Management intends for the fund, including earnings thereon, to provide for all
eventual decommissioning expenditures on an after-tax basis. The trust's sources
of decommissioning funds under the COMReP program include investment components
of life insurance policy proceeds, return on investment and the cash transfers
from SCE&G described above. SCE&G records its liability for decommissioning
costs in deferred credits.
Gas Operations
Gas Sales
The Company derives gas sales revenues from three sources: SCE&G's gas
distribution, Pipeline Corporation's gas transmission and Energy Marketing's
retail market in Georgia. Energy marketing began signing up retail customers on
November 1, 1998. By December 31, 1998, Energy Marketing had approximately
76,500 such customers. However, due to the timing lag between signing up
customers and actually billing them, sales of gas and associated revenues by
Energy Marketing were insignificant as of December 31, 1998, and are not
included in the following discussion.
In 1998 the Company's residential sales accounted for 24% of gas sales
revenues; commercial sales 18%; industrial sales 46%; and sales for resale 12%.
During the same period, SCE&G's residential sales accounted for 43% of gas sales
revenues; commercial sales 31%; industrial sales 26%. Dekatherm sales by
classification for the years ended December 31, 1998 and 1997 are presented
below:
Sales
Dekatherms (000)
The Company SCE&G
Classification 1998 1997 % Change 1998 1997 % Change
- ----------------------------------------------------------------------------
Residential 11,917 11,920 - 11,917 11,920 -
Commercial 11,383 10,986 3.6 11,294 10,905 3.6
Industrial 62,030 55,337 12.1 18,093 15,729 15.0
Sales for resale 15,744 16,667 (5.5) - - -
Transportation gas 4,435 5,804 (23.6) 2,004 2,677 (25.2)
- ----------------------------------------------------------------------------
Total 105,509 100,714 4.8 43,308 41,231 5.0
===========================================================================
The Company's and SCE&G's gas sales volume increased for 1998 as a
result of increased sales to electric generation facilities and customer growth.
During 1998 the Company recorded a net increase of 4,256 customers, increasing
its total customers to 256,957. SCE&G recorded a net increase of 4,255 gas
customers, increasing its total customers to 256,842.
The demand for gas is affected by conservation, the weather, the price
relationship between gas and alternate fuels and other factors.
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.
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. Energy Marketing acquires and sells natural gas in
regulated and deregulated markets. Energy Marketing has not supplied natural gas
to any affiliate for use in providing regulated gas utility services.
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 Southern Natural (expiring in 2003) and Transco (expiring in 2008 and
2017). The volume of gas which Pipeline Corporation is entitled to transport
under these contracts on a firm basis is 188 MMCF from Southern Natural and 105
MMCF from Transco. Additional natural gas volumes are brought to Pipeline
Corporation's system as capacity is available for interruptible transportation.
SCE&G, under contract with Pipeline Corporation, is entitled to receive a daily
contract demand of 224,270 dekatherms. The contract allows SCE&G to receive
amounts in excess of this demand based on availability.
During 1998 Pipeline Corporation's average cost per MCF of natural gas
purchased for resale, excluding firm service demand charges, was $2.39 compared
to $2.71 during 1997. SCE&G's average cost per MCF was $3.67 and $3.94 during
1998 and 1997, respectively.
Pipeline Corporation has engaged in hedging activities on the New York
Mercantile Exchange (NYMEX) of its gas supply pursuant to a limited program
authorized and monitored by the PSC. Any gains or losses associated with that
hedging activity are accounted for in Pipeline Corporation's purchased gas
adjustment clause and, therefore, have no impact on net income.
To meet the requirements of its high priority natural gas customers
during periods of maximum demand, Pipeline Corporation supplements its supplies
of natural gas from two LNG plants. The LNG plants are capable of storing the
liquefied equivalent of 1,880 MMCF of natural gas, of which approximately 928
MMCF were in storage at December 31, 1998. On peak days the LNG plants can
regasify up to 150 MMCF per day. Additionally, Pipeline Corporation had
contracted for 6,447 MMCF of natural gas storage space of which 3,888 MMCF were
in storage on December 31, 1998.
The Company believes that supplies under contract and supplies
available for spot market purchase are adequate to meet existing customer
demands and to accommodate growth.
Curtailment Plans
The PSC has established allocation priorities applicable to firm and
interruptible capacities on Pipeline Corporation. The curtailment plan
priorities of Pipeline Corporation apply to the resale distribution customers of
Pipeline Corporation, including SCE&G.
Gas Marketing
Energy Marketing markets natural gas and light hydrocarbons and
provides energy-related risk management services to producers and consumers. In
1998, Energy Marketing began marketing natural gas to residential and commercial
customers in Georgia. In 1996, the FERC approved Energy Marketing's application
to become a power marketer, allowing Energy Marketing to buy and sell large
blocks of electric capacity in wholesale markets.
Propane Operations
SCANA Propane Gas, Inc. purchases, delivers and sells propane in the
Southeast. SCANA Propane Storage, Inc. owns and operates a 60-million gallon
underground propane storage facility near Rock Hill, South Carolina and leases
storage space to industrial companies, utilities and others. Pipeline
Corporation, through a wholly owned subsidiary, owns and operates a 62-mile
propane pipeline that connects SCANA Propane Services, Inc.'s propane storage
facility with the Dixie Pipeline System which traverses central South Carolina.
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 otherwise orders, 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.
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.
(See "Capital Requirements and Financing Program.")
SCE&G holds licenses under the Federal Water Power Act or the Federal
Power Act with respect to all of its hydroelectric projects. The expiration
dates of the licenses covering the projects are as follows:
Project Capability (KW) License Expiration
Neal Shoals 5,000 2036
Parr Shoals 14,000 2020
Stevens Creek 9,000 2025
Columbia 10,000 2000
Saluda 206,000 2007
Fairfield Pumped Storage 512,000 2020
SCE&G filed an application for a new license for Columbia on June 30,
1998.
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 Federal
government takes over a project or the FERC issues a license to another
applicant, the original licensee is entitled to be paid its net investment in
the project, not to exceed fair value, plus severance damages.
In May 1996 the FERC approved the Company's application establishing
open access transmission tariffs and requesting authorization to sell bulk power
to wholesale customers at market-based rates.
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. 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.
In 1998 the NRC completed the Systematic Assessment of Licensee
Performance (SALP) for Summer Station. The SALP assesses the four functional
areas of plant operations, maintenance, engineering and plant support. In 1998
Summer Station received a superior rating (the NRC's highest rating) in each of
the four functional areas.
National Energy Policy Act of 1992 and FERC Orders 636 and 888
The Company's regulated business operations were impacted by the NEPA
and FERC Orders No. 636 and 888. NEPA was 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. See "Competition" for a discussion of FERC
Order 888. Order No. 636 was 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
continues to be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any material adverse
impact on the results of operations, cash flows, financial position or business
prospects.
Rate Matters
For a discussion of the impact of various rate matters, see Regulatory
Matters in the Liquidity and Capital Resources section of Management's
Discussion and Analysis for the Company and SCE&G.
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 annually based on
projected fuel costs for the ensuing twelve-month period, adjusted for any
overcollection or undercollection from the preceding twelve-month period. SCE&G
has the right to request a formal proceeding at any time should circumstances
dictate such a review. In the April 1998 annual review of the fuel cost
component of electric rates, the PSC left the rate unchanged at 12.85 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 1998 review the PSC left the base cost of gas unchanged at 48.182
cents per therm.
Environmental Matters
General
Federal and state authorities have imposed environmental regulations
and standards relating primarily to air emissions, wastewater discharges and
solid, toxic and hazardous waste management. Developments in these areas may
require that equipment and facilities be modified, supplemented or replaced. The
ultimate effect of these regulations and standards upon existing and proposed
operations cannot be forecast.
Capital Expenditures
In the years 1996 through 1998, capital expenditures for environmental
control amounted to approximately $75.5 million. This was in addition to
expenditures included in "Other operation" and "Maintenance" expenses, which
were approximately $18.8 million, $17.1 million, and $13.9 million during 1998,
1997 and 1996, respectively. It is not possible to estimate all future costs for
environmental purposes, but forecasts for capitalized expenditures are $34.6
million for 1999 and $108.3 million for the four-year period 2000 through 2003.
These expenditures are included in the Company's construction program.
Air Quality Control
The Clean Air Act requires electric utilities to reduce emissions of
sulfur dioxide and nitrogen oxide substantially by the year 2000. These
requirements are being phased in over two periods. The first phase had a
compliance date of January 1, 1995 and the second, January 1, 2000. The
Company's facilities did not require modifications to meet the requirements of
Phase I. The Company will most likely meet the Phase II requirements through the
burning of natural gas and/or lower sulfur coal in its generating units and the
purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide
burners are being installed to reduce nitrogen oxide emissions to the levels
required by Phase II. Air toxicity regulations for the electric generating
industry are likely to be promulgated around the year 2000.
SCE&G and GENCO filed compliance plans with DHEC related to Phase II
sulfur dioxide requirements in 1995 and Phase II nitrogen oxide requirements in
1997. The Company currently estimates that air emissions control equipment will
require capital expenditures of $170 million over the 1999-2003 period to
retrofit existing facilities, with increased operation and maintenance cost of
approximately $18 million per year. To meet compliance requirements through the
year 2008, the Company anticipates total capital expenditures of approximately
$268 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 program in monitoring and controlling thermal discharges and
strategies for toxicity reduction in wastewater streams. The Company has been
developing compliance plans for these initiatives.
Comprehensive Environmental Response, Compensation and Liabilities Act
(Superfund) and Environmental Assessment Program
The Company has an environmental assessment program to identify and
assess current and former operations sites that could require environmental
cleanup. As site assessments are initiated, estimates are made of the
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations. Such amounts are deferred and
amortized with recovery provided through rates. The Company has also recovered
portions of its environmental liabilities through settlements with various
insurance carriers. As of December 31, 1998, the Company has recovered all
amounts previously deferred for its electric operations. The Company expects to
recover all deferred amounts related to its gas operations by December 2002.
Deferred amounts, net of amounts recovered through rates and settlements,
totaled $21.3 million and $32.4 million at December 31, 1998 and 1997,
respectively. The deferral includes the estimated costs associated with the
matters discussed below.
o 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 encompasses approximately 30 acres and includes
properties which were locations for industrial operations, including a wood
preserving (creosote) plant, one of SCE&G's decommissioned manufactured gas
plants, properties owned by the National Park Service and the City of
Charleston, and private properties. The site has not been placed on the
National Priorities List, but may be added in the future. The PRPs have
negotiated an administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope of Work. Field
work began in November 1993, and the EPA approved a Remedial Investigation
Report in February 1997 and a Feasibility Study Report in June 1998. In
July 1998, the EPA approved SCE&G's Removal Action Work Plan for soil
excavation. SCE&G completed Phase One of the Removal Action in 1998, at a
cost of approximately $1.5 million. Phase Two will include excavation and
installation of several permanent barriers to mitigate coal tar seepage.
Phase Two began in November 1998, and is expected to cost approximately
$2.2 million. On September 30, 1998 a Record of Decision was issued which
sets forth the EPA's view of the extent of each PRP's responsibility for
site contamination and the level to which the site must be remediated. On
January 13, 1999, the EPA issued a Unilateral Administrative Order for
Remedial Design and Remedial Action directing SCE&G to design and carry out
a plan of remediation for the Calhoun Park site. The Order is temporarily
stayed pending further negotiations between SCE&G and the EPA.
In October 1996 the City of Charleston and SCE&G settled all environmental
claims the City may have had against SCE&G involving the Calhoun Park area
for a payment of $26 million over four years (1996-1999) by SCE&G to the
City. SCE&G is recovering the amount of the settlement, which does not
encompass site assessment and cleanup costs, through rates in the same
manner as other amounts accrued for site assessments and cleanup as
discussed above. As part of the environmental settlement, SCE&G has agreed
to construct an 1,100 space parking garage on the Calhoun Park site and to
transfer the facility to the City in exchange for a 20-year municipal bond
backed by revenues from the parking garage and a mortgage on the parking
garage. The total amount of the bond is not to exceed $16.9 million, the
maximum expected project cost. The parking garage is currently under
construction, and is scheduled for completion in the spring of the year
2000.
o SCE&G owns three other decommissioned manufactured gas plant sites which
contain residues of by-product chemicals. For the site located in
Sumter, South Carolina, effective September 15, 1998, SCE&G entered into
a Remedial Action Plan Contract with DHEC pursuant to which it agreed to
undertake a full site investigation and remediation under the oversight
of DHEC. Site investigation and characterization are proceeding
according to schedule. Upon selection and successful implementation of a
site remedy, DHEC will give SCE&G a Certificate of Completion, and a
covenant not to sue. SCE&G is continuing to investigate the other two
sites, and is monitoring the nature and extent of residual
contamination.
Solid Waste Control
In 1998 DHEC promulgated regulations for the disposal of industrial
solid waste as directed by the South Carolina Solid Waste Policy and Management
Act of 1991. The full impact of these regulations is not yet known; however,
they may significantly increase SCE&G's and GENCO's costs of construction and
operation of existing and future ash management facilities.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 required 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 mil 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 nuclear fuel storage capability until at least 2009 and
expects to be able to expand its storage capacity to accommodate the spent
nuclear fuel output for the life of the plant through rod consolidation, dry
cask storage or other technology as it becomes available. The Act also imposes
on utilities the primary responsibility for storage of their spent nuclear fuel
until the repository is available.
Year 2000 Issue
For a discussion of the measures being taken to address the Year 2000
issue, see Other Matters in the Liquidity and Capital Resources section of
Management's Discussion and Analysis for the Company and SCE&G.
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 for the
Company and for SCE&G, which is incorporated herein by reference.
On December 1, 1997, Petroleum Resources sold substantially all of its
assets for $110 million. The resulting gain of $17.6 million was recorded in
"Other Income." Proceeds from the sale were used to repurchase approximately 3.7
million shares of SCANA's outstanding common stock through open market
purchases. All of the repurchased shares were retired, reducing the number of
shares issued and outstanding.
For a description of the Company's investments in various
telecommunications companies, see Other Matters in the Liquidity and Capital
Resources section of Management's Discussion and Analysis for the Company.
ITEM 2. PROPERTIES
The Company owns, directly or indirectly, all of the capital stock of
each of its subsidiaries except for the preferred stock of SCE&G, the preferred
securities of SCE&G Trust I and 30% of the common stock of an indirect
subsidiary. It also has investments in two LLC's, one of which is building and
will operate a cogeneration facility in Charleston, South Carolina, and the
other which is constructing a lime production facility. The Company owns no
other significant property.
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-Segments of Business-Nonregulated Businesses."
Electric
Information on electric generating facilities, all of which are owned by
SCE&G except as noted, are as follows:
Net Generating
Present Year Capability
Facility Fuel Capability Location In-Service (Summer Rating)(KW)
Steam
Urquhart Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 415,000
Wateree Coal Eastover, SC 1970 720,000
Williams (1) Coal Goose Creek, SC 1973 580,000
Summer (2) Nuclear Parr, SC 1984 635,000
D-Area (3) Coal DOE Savannah
River Site, SC 1995 35,000
Cope Coal Cope, SC 1996 420,000
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
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr Gas/Oil Parr, SC 1970 60,000
Williams 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 4,387,000
(1) The steam unit at Williams Station is owned by GENCO.
(2) Represents SCE&G's two-thirds portion of the Summer Station.
(3) This plant is leased from the DOE and is dedicated to DOE's Savannah
River Site steam needs. "Net Generating Capability" for this plant is
expected average hourly output. The lease expires on October 1, 2005.
SCE&G owns 428 substations having an aggregate transformer capacity of
21,928,145 KVA. The transmission system consists of 3,140 miles of lines and the
distribution system consists of 16,346 pole miles of overhead lines and 3,590
trench miles of underground lines.
Gas
Natural Gas
SCE&G's gas system consists of approximately 11,963 miles of
distribution mains and related service facilities.
Pipeline Corporation's gas system consists of approximately 1,919 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 and the other in Salley, South Carolina. The Charleston facility
can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF
of natural gas. The Salley facility can store the liquefied equivalent of 900
MMCF of natural gas and has no liquefying capabilities. On peak days, the
Charleston facility can regasify up to 60 MMCF per day and the Salley facility
can regasify up to 90 MMCF.
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 MMCF
per day. These facilities can store the equivalent of 430 MMCF of natural gas.
Transit
SCE&G owns 61 motor coaches used in the operation of the Columbia
transit system. The Columbia system is comprised of fifteen routes covering 177
miles.
Effective October 1, 1996, SCE&G transferred ownership and operation of
the Charleston transit system to the City of Charleston. As part of the
transfer, the Company conveyed to the City ownership of facilities, equipment
and four motor coaches used in the operation of the transit system. The City and
SCE&G entered into an interim operating agreement whereby SCE&G would operate
the system for the City until a Regional Transit Authority was established. On
January 1, 1999, the Regional Transit Authority was established and became
responsible to operate and maintain the Charleston system.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1., BUSINESS Rate
Matters and BUSINESS - Environmental Matters Comprehensive Environmental
Response, Compensation and Liabilities Act (Superfund) and Environmental
Assessment Program and Note 10 of Notes to Consolidated Financial Statements
appearing in Item 8., FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for the
Company and for SCE&G.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
CORPORATE STRUCTURE
SCANA CORPORATION
A holding company, owning thirteen
direct, wholly owned subsidiaries
SOUTH CAROLINA ELECTRIC SCANA ENERGY MARKETING, INC.
& GAS COMPANY Markets electricity, natural gas
Generates and sells electricity and other light hydrocarbons
to wholesale and retail customers, primarily in the Southeast.
purchases, sells and transports Markets natural gas in Georgia's
natural gas at retail and provides deregulated natural gas market.
provides public transit service Provides energy-related risk
in Columbia. management services to producers
and consumers.
SOUTH CAROLINA GENERATING
COMPANY, INC. SERVICECARE, INC.
Owns and operates William Station Provides energy-related products
and sells electricity to SCE&G. and services, principally service
contracts on home appliances and
SOUTH CAROLINA FUEL COMPANY, INC. home security services.
Acquires, owns and provides
financing for SCE&G's nuclear PRIMESOUTH, INC.
fuel, fossil fuel and sulfur Engages in power plant management
dioxide emission allowance. and maintenance services.
SOUTH CAROLINA PIPELINE CORPORATION SCANA RESOURCES, INC.
Purchases, sells and transports Conducts energy-related businesses
natural gas to wholesale and direct and services.
industrial customers. Owns and
operates a propane pipeline and two SCANA PETROLEUM RESOURCES, INC.
LNG plants for the liquefaction, In liquidation following sale of
storage and regasification of natural oil and gas properties.
gas.
SCANA COMMUNICATIONS, INC. SCANA DEVELOPMENT CORPORATION
-------------------------- -----------------------------
Provides fiber optic telecommun- Engaged in the sale of real estate.
ications in South Carolina, a (In liquidation.)
public safety radio communi-
cations network, and tower
construction, management and rental
services for wireless providers and
invests in telecommunications
companies.
SCANA PROPANE GAS, INC.
Purchases, delivers and sells
propane.
SCANA PROPANE STORAGE, INC.
Owns and operates an underground
propane storage facility and
leases storage to industries,
utilities and others.
Each of the above listed companies is organized and incorporated under the
laws of the State of South Carolina.
EXECUTIVE OFFICERS OF SCANA CORPORATION
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
a resignation is submitted, or unless the Board of Directors shall otherwise
determine.
Positions Held During
Name Age Past Five Years Dates
W. B. Timmerman 52 Chairman of the Board and
Chief Executive Officer 1997-present
Chief Operating Officer 1996-1997
President 1995-present
President, SCI 1996-1997
Executive Vice President *-1995
Chief Financial Officer and Controller *-1996
Senior Vice President *-1994
J. L. Skolds 48 Group Executive - SCANA Electric Group 1997-present
President and Chief Operating
Officer,SCE&G 1996-present
Senior Vice President - Generation, SCE&G *-1996
Senior Vice President - Nuclear Operations,
SCE&G 1994-1995
Vice President - Nuclear Operations, SCE&G *-1994
A. H. Gibbes 52 Group Executive - SCANA Gas Group 1996-present
President, Pipeline Corporation 1996-present
President, C&T Pipeline, LLC 1996-present
Senior Vice President, General
Counsel and Assistant Secretary *-1996
Vice President and General Counsel *-1994
President and Treasurer, SCANA
Development Corp. *-present
C. B. Novinger** 49 Senior Vice President - Administration,
Governmental and Public Affairs *-present
K. B. Marsh 43 Senior Vice President - Finance,
Chief Financial and Controller 1998-present
Vice President - Finance, Chief
Financial Officer and Controller 1996-1998
Vice President - Finance, Treasurer and
Secretary *-1996
H. T. Arthur, II 53 Senior Vice President and General Counsel 1998-present
Vice President and General Counsel 1996-1998
Assistant Secretary, SCE&G, and other
subsidiaries 1996-present
Vice President and General Counsel,
Pipeline Corporation *-1996
A. M. Milligan 39 Senior Vice President - Marketing 1998-present
Director of Consumer Credit Marketing,
Barnett Bank, N. A., Florida 1996-1998
Senior Vice President - Marketing,
Barnett Card Services, Florida *-1996
G. J. Bullwinkel 50 President, SCI 1997-present
Senior Vice President- Retail Electric,
SCE&G 1995-present
Senior Vice President- Fossil & Hydro
Production, SCE&G *-1994
* Indicates position held at least since March 1, 1994.
** C. B. Novinger has announced her retirement effective May 26, 1999.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
COMMON STOCK INFORMATION - SCANA Corporation
1998 1997
4th 3rd 2nd 1st 4th 3rd 2nd 1st
Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr.
Price Range: (a)
High 37 1/4 33 7/8 31 3/8 31 29 15/16 25 5/8 25 5/8 26 5/8
Low 31 5/16 28 1/2 28 27 7/8 24 23 7/8 23 3/8 24 7/8
(a) As reported on the New York Stock Exchange Composite Listing.
Dividends Per Share:
1998 Amount Date Declared Date Paid
First Quarter .3850 February 17, 1998 April 1, 1998
Second Quarter .3850 April 23, 1998 July 1, 1998
Third Quarter .3850 August 19, 1998 October 1, 1998
Fourth Quarter .3850 October 20, 1998 January 1, 1999
1997 Amount Date Declared Date Paid
First Quarter .3775 February 18, 1997 April 1, 1997
Second Quarter .3775 April 24, 1997 June 30, 1997
Third Quarter .3775 August 20, 1997 October 1, 1997
Fourth Quarter .3775 October 21, 1997 January 1, 1998
As of December 31, 1998 1997
Number of common shares outstanding 103,572,623 107,321,113
Number of common shareholders of record 30,983 33,395
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 26,
1999 was 103,572,623 which was held by 30,679 shareholders of record. All of
SCE&G's common stock is owned by SCANA and has no market. During 1998 and 1997
SCE&G paid $167.3 million and $141.4 million, respectively, in cash dividends to
SCANA.
SECURITIES RATINGS (As of December 31, 1998)
SCANA Corporation South Carolina Electric & Gas Company
First First and Trust
Rating Medium-Term Mortgage Refunding Preferred Preferred Commercial
Agency Notes Bonds Mortgage Bonds Stock Securities Paper
Duff &
Phelps A- A+ A+ A A D-1
Moody's A3 A1 A1 a2 a2 P-1
Standard
& Poor's A A+ A+ A A A-1
Further reference is made to Note 5 of Notes to Consolidated Financial
Statements for the Company and SCE&G.
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 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, 1998 approximately $25.1
million of retained earnings were restricted as to payment of cash dividends on
common stock of SCE&G.
ITEM 6. SELECTED FINANCIAL DATA
SCANA SELECTED FINANCIAL DATA
For the Years Ended December 31, 1998 1997 1996 1995 1994
- ------------------------------------ (Millions of dollars, except
statistics and per share amounts)
Statement of Income Data
Operating Revenues $1,632 $1,523 $1,513 $1,353 $1,322
Operating Income 345 314 314 288 260
Other Income 13 38 29 8 (30)
Net Income 223 221 215 168 115
Balance Sheet Data
Utility Plant, Net $3,787 $3,648 $3,529 $3,469 $3,294
Total Assets 5,281 4,932 4,759 4,534 4,317
Capitalization:
Common equity 1,746 1,788 1,684 1,555 1,359
Preferred Stock (Not subject to
purchase or sinking fund) 106 106 26 26 26
Preferred Stock, net (Subject to
purchase or sinking fund) 11 12 43 46 50
SCE&G - obligated mandatorily redeemable
preferred securities of SCE&G's subsidiary, SCE&G Trust I, holding solely
$50 million principal amount of 7.55% Junior Subordinated Debentures of
SCE&G, due 2027 50 50 - - -
Long-term debt, net 1,623 1,566 1,581 1,589 1,549
- ------------------------------------
Total Capitalization $3,536 $3,522 $3,334 $3,216 $2,984
===================================== =
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions) 105.3 107.1 105.1 99.0 94.7
Earnings Per Weighted Average Share
of Common Stock $ 2.12 $2.06 $2.05 $1.70 $1.22
Dividends Declared Per Share of Common Stock $ 1.54 $1.51 $1.47 $1.44 $1.41
Common Shares Outstanding (Year-End)
(Millions) 103.6 107.3 106.1 103.6 96.0
Book Value Per Share of Common Stock
(Year-End) $16.86 $16.66 $15.86 $15.00 $14.15
Number of Common Shareholders of Record 30,983 33,395 36,178 38,231 39,516
Other Statistics
Electric:
Customers (Year-End) 517,447 503,905 493,320 484,354 476,412
Total sales (Million KWH) 21,203 18,853 18,904 17,779 17,009
Residential:
Average annual use per customer (KWH) 14,481 13,214 14,149 13,859 13,048
Average annual rate per KWH $.0801 $.0799 $.0785 $.0747 $.0743
Generating capability - Net MW (Year-End) 4,387 4,350 4,316 4,282 3,876
Territorial peak demand - Net MW 3,935 3,734 3,698 3,683 3,444
Gas:1
Customers (Year-End) 256,957 252,701 248,681 243,523 238,614
Sales, excluding transportation
(Thousand Therms) 1,010,742 949,100 896,294 882,511 781,109
Residential:
Average annual use per customer (Therms) 521 531 639 570 543
Average annual rate per therm $.86 $.86 $.74 $.82 $.84
1 Excludes data from Energy Marketing. See previous discussion at Gas
Operations.
SCE&G SELECTED FINANCIAL DATA
For the Years Ended December 31, 1998 1997 1996 1995 1994
(Millions of dollars, except statistics)
Statement of Income Data
Operating Revenues $1,451 $1,338 $1,345 $1,211 $1,181
Operating Income 312 282 286 256 230
Other Income 13 9 4 9 7
Net Income 227 195 190 169 152
Earnings Available for Common Stock 219 186 185 163 146
Balance Sheet Data
Utility Plant, Net $3,432 $3,310 $3,197 $3,158 $2,998
Total Assets 4,246 4,054 3,959 3,802 3,587
Capitalization:
Common equity 1,499 1,447 1,413 1,315 1,133
Preferred Stock (Not subject
to purchase or sinking funds) 106 106 26 26 26
Preferred Stock, Net (Subject to
purchase or sinking funds) 11 12 43 46 50
Company - Obligated mandatorily
redeemable preferred securities of the
Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million,
principal amount of 7.55% of Junior Subordinated Debentures
of the Company, due 2027 50 50 - - -
Long-term debt, net 1,206 1,262 1,277 1,279 1,231
Total Capitalization $2,872 $2,877 $2,759 $2,666 $2,440
=====================================================================================================
Other Statistics
Electric:
Customers (Year-End) 517,472 503,930 493,346 484,381 476,438
Total sales (Million KWH) 21,204 18,853 18,012 17,585 16,840
Residential:
Average annual use per customer (KWH)14,481 13,214 14,149 13,859 13,048
Average annual rate per KWH $.0801 $.0799 $.0785 $.0747 $.0743
Generating capability - Net MW
(Year-End) 3,807 3,790 3,756 3,722 3,316
Territorial peak demand - Net MW 3,935 3,734 3,698 3,683 3,444
Gas:
Customers (Year-End) 256,842 252,587 248,496 242,342 238,433
Sales, excluding transportation
(Thousand Therms) 413,038 385,537 390,451 362,384 322,837
Residential:
Average annual use per customer
(Therms) 521 531 639 570 538
Average annual rate per therm $.86 $.86 $.74 $.82 $.84
- ----
SCANA CORPORATION
FINANCIAL SECTION
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or elsewhere in this
annual report) which are not statements of historical fact are intended to be,
and are hereby identified as, "forward looking statements" for purposes of the
safe harbor provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties, and that actual
results could differ materially from those indicated by such forward-looking
statements. Important factors that could cause actual results to differ
materially from those indicated by such forward-looking statements include, but
are not limited to, the following: (1) that the information is of a preliminary
nature and may be subject to further and/or continuing review and adjustment,
(2) changes in the utility regulatory environment, including the pace of
deregulation of retail natural gas and electricity markets in the United States,
(3) changes in the economy in areas served by SCANA's subsidiaries, (4) the
impact of competition from other energy suppliers, (5) the management of the
Company's operations, (6) variations in prices of natural gas and fuels used for
electric generation, (7) growth opportunities for the Company's regulated and
non-regulated subsidiaries, (8) the results of financing efforts, (9) changes in
the Company's accounting policies, (10) weather conditions in areas served by
the Company's utility subsidiaries, (11) performance of the telecommunications
companies in which the Company has made significant investments, (12) inflation,
(13) exposure to environmental issued and liabilities, (14) changes in
environmental regulation, (15) successful correction of any material Year 2000
problem or, alternatively, successful implementation of a contingency plan by
the Company and any critical third party suppliers and (15) the other risks and
uncertainties described from time to time in the Company's periodic reports
filed with the SEC. The Company disclaims any obligation to update any
forward-looking statements.
COMPETITION
The electric utility industry continues a major transition that is
resulting in expanded market competition and less regulation. Deregulation of
electric wholesale and retail markets is creating 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. Legislative initiatives at
the Federal and state levels are being considered and, if enacted, could mandate
market deregulation. The pace of deregulation, future prices of electricity, and
the regulatory actions which may be taken by the PSC and the FERC in response to
the changing environment cannot be predicted. However, the FERC, in issuing
Order 888 in April 1996, accelerated competition among electric utilities by
providing for open access to wholesale transmission service. Order 888 requires
utilities under FERC jurisdiction that own, control or operate transmission
lines to file nondiscriminatory open access tariffs that offer to others the
same transmission service they provide themselves. The FERC has also permitted
utilities to seek recovery of wholesale stranded costs from departing customers
by direct assignment. Approximately two percent of SCANA's electric revenues is
under FERC jurisdiction for the purpose of setting rates for wholesale service.
Legislation is pending in South Carolina that would deregulate the state's
retail electric market and enable customers to choose their supplier of
electricity. The Company is not able to predict whether the legislation will be
enacted and, if it is, the conditions it will impose on utilities that currently
operate in the state and future market participants.
The Company is aggressively pursuing actions to position itself
strategically for the transformed environment. The Company's entry into the
newly deregulated retail natural gas market in Georgia is designed in part to
provide a potential market for any future deregulated electric industry (see
Georgia Retail Gas Market below). In addition, SCE&G has undertaken a variety of
initiatives, including reductions in staffing levels and the accelerated
recovery of its electric regulatory assets. SCE&G has also established open
access transmission tariffs and is selling bulk power to wholesale customers at
market-based rates. A significant new management information system was
implemented in 1998, and a new customer information system will be fully
implemented in the first half of 1999. Marketing of services to commercial and
industrial customers has increased significantly. SCE&G has obtained long term
power supply contracts with a significant portion of its industrial customers.
The Company believes that these actions as well as numerous others that have
been and will be taken demonstrate its commitment to succeed in the new
operating environment to come.
Regulated public utilities are allowed to record as assets some costs
that would be expensed by other enterprises. If deregulation or other changes in
the regulatory environment occur, the Company may no longer be eligible to apply
this accounting treatment and may be required to eliminate such regulatory
assets from its balance sheet. Although the potential effects of deregulation
cannot be determined at present, discontinuation of the accounting treatment
could have a material adverse effect on the Company's results of operations in
the period that a write-off would be required. It is expected that cash flows
and the financial position of the Company would not be materially affected by
the discontinuation of the accounting treatment. The Company reported
approximately $216 million and $71 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets and
liabilities of approximately $130 million and $56 million, respectively, on its
balance sheet at December 31, 1998.
The Company's generation assets are exposed to considerable financial
risks in a deregulated electric market. If market prices for electric generation
do not produce adequate revenue streams and the enabling legislation or
regulatory actions do not provide for recovery of the resulting stranded costs,
the Company could be required to write down its investment in these assets. The
Company cannot predict whether any write-downs will be necessary and, if they
are, the extent to which they would adversely affect the Company's results of
operations in the period in which they are recorded. As of December 31, 1998,
the Company's net investment in fossil/hydroelectric generation and nuclear
generation assets was $1,220.3 million and $619.2 million, respectively.
Georgia Retail Gas Market
In October 1998, Georgia's retail natural gas market opened to
competition. The Company's subsidiary, Energy Marketing, is among the 19
marketers authorized to market natural gas to the 1.4 million residential and
commercial customers served by a Georgia utility. Energy Marketing is offering
customers a competitive rate without requiring a long-term contract or deposit.
Energy Marketing's strategy relies heavily on direct advertising, including
incentives to customers who choose Energy Marketing to be their new service
provider. In addition, Energy Marketing has numerous alliances and affinity
relationships with electric member cooperatives, churches and community
organizations, among others, through which it offers incentives. Energy
Marketing's success in acquiring customers is significantly exceeding its
projections. As a result, expenses are also significantly higher than expected.
For the period ending December 31, 1998, Energy Marketing had incurred
approximately $8 million in losses (net of taxes), including startup costs which
were expensed as incurred. At the current rate of expansion, Energy Marketing
anticipates incurring losses during 1999 equal or greater than those experienced
in 1998. The level of future revenues and expenditures, including startup costs,
is dependent on several factors that cannot be reasonably predicted. These
factors included how rapidly Energy Marketing gains market share, the intensity
of competition as it continues to develop, the margin Energy Marketing is able
to achieve on gas sales and its ability to find industrial interruptible
customers to purchase available capacity.
LIQUIDITY AND CAPITAL RESOURCES
The Company's cash requirements arise primarily from SCE&G's operational
needs, SCE&G'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 continue their ongoing construction programs, it may be
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 and other regulatory
relief if requested.
SCANA and Westvaco each own a 50% interest in Cogen South LLC (Cogen).
Cogen was formed to build and operate a cogeneration facility at Westvaco's
Kraft Division Paper Mill in North Charleston, South Carolina. Construction of
the facility began in September 1996 and is in the final stages. Construction
financing of approximately $170 million was provided to Cogen by banks. On
December 30, 1998, SCANA provided a capital contribution of approximately $15.5
million to Cogen. On September 10, 1998, the contractor in charge of
construction filed suit in Circuit Court seeking approximately $51 million from
Cogen, alleging that construction cost overruns were incurred, and that the
construction contract provides for recovery of these costs. In addition to
Cogen, Westvaco, SCE&G and SCANA were also named in the suit. SCANA and the
other defendants believe the suit is without merit and are mounting an
appropriate defense. SCANA does not believe that the resolution of this issue
will have a material impact on its results of operations, cash flows or
financial position.
On August 7, 1996 the City of Charleston executed 30-year electric and
gas franchise agreements with SCE&G. In consideration for the electric franchise
agreement, SCE&G is paying the City $25 million over seven years (1996 through
2002) and has donated to the City the existing transit assets in Charleston. The
$25 million is included in electric plant-in-service. In settlement of
environmental claims the City may have had against SCE&G involving the Calhoun
Park area, where SCE&G and its predecessor companies operated a manufactured gas
plant until the 1960's, SCE&G is paying the City $26 million over a four-year
period (1996 through 1999). As part of the environmental settlement, SCE&G has
agreed to construct an 1,100 space parking garage on the Calhoun Park site and
to transfer the facility to the City in exchange for a 20-year municipal bond
backed by revenues from the parking garage and a mortgage on the parking garage.
The total amount of the bond is not to exceed $16.9 million, the maximum
expected project cost. The parking garage is currently under construction, and
is scheduled for completion in the spring of the year 2000.
The revised estimated primary cash requirements for 1999, excluding requirements
for fuel liabilities and short-term borrowings, and the actual primary cash
requirements for 1998 are as follows:
1999 1998
- ----------------------------------------------------------------------------
(Millions of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $308 $281
Nuclear fuel expenditures 5 23
Maturing obligations, redemptions and
sinking and purchase fund requirements 158 257
- ----------------------------------------------------------------------------
Total $471 $561
============================================================================
Approximately 45% of total cash requirements (after payment of dividends)
was provided from internal sources in 1998 as compared to 62% in 1997.
SCANA 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 subsidiaries, to reduce short-term debt
incurred in connection therewith or for general corporate purposes. At December
31, 1998, SCANA had registered with the SEC and available for issuance $200.0
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 twelve
consecutive months out of the fifteen months prior to the month of issuance are
at least twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1998 the Bond Ratio
was 5.30. The issuance of additional Class A Bonds also is restricted to an
additional principal amount equal to (i) 60% of unfunded net property additions
(which unfunded net property additions totaled approximately $396 million at
December 31, 1998), (ii) retirements of Class A Bonds (which retirement credits
totaled $100.3 million at December 31, 1998), and (iii) cash on deposit with the
Trustee.
SCE&G has a bond indenture dated April 1, 1993 (New Mortgage) covering
substantially all of its electric properties under which its future
mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the
New Mortgage on the basis of a like principal amount of Class A Bonds issued
under the Old Mortgage which have been deposited with the Trustee of the New
Mortgage (of which $315 million were available for such purpose at December 31,
1998), until such time as two thirds of all Class A Bonds are held by the
Trustee. Thereafter, the Old Mortgage may be amended to allow New Bonds to be
issuable on the basis of property additions in a principal amount equal to 70%
of the original cost of electric and common plant properties (compared to 60% of
value for Class A Bonds under the Old Mortgage), cash deposited with the
Trustee, and retirement of New Bonds. New Bonds will be issuable under the New
Mortgage only if adjusted net earnings (as therein defined) for twelve
consecutive months out of the eighteen months immediately preceding the month of
issuance are at least twice the annual interest requirements on all outstanding
bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond
Ratio). For the year ended December 31, 1998 the New Bond Ratio was 6.72.
SCE&G expects in 1999 to amend the Old Mortgage to conform certain of its
provisions to those of the New Mortgage, including (i) the elimination of the
maintenance and replacement fund and the utilization of unfunded net property
additions previously applied in satisfaction thereof as a basis for the issuance
of bonds; (ii) the issuance of bonds in a principal amount equal to 70% of
unfunded net property additions instead of 60%; and (iii) the conformance of the
interest coverage requirements for the issuance of bonds to those of the New
Mortgage.
The following additional financing transactions have occurred since
December 31, 1997:
o On January 13, 1998 SCANA issued $60 million of medium-term notes due
January 13, 2003 at an interest rate of 6.05%. The funds were used to
refinance unsecured bank loans in a like total amount.
o On July 8, 1998, SCANA issued $75 million of medium-term notes having
an annual interest rate of 6.25% and maturing on July 8, 2003. These
funds were used to finance an additional investment of $75 million in
Powertel, Inc.
o On October 23, 1998, SCANA issued $115 million of medium-term notes
having an annual interest rate of 5.81% and maturing on October 23,
2008. These funds were used to reduce short-term debt.
o On October 29, 1998, SCANA's shelf registration statement filed with
the SEC became effective, providing for the issuance of up to an
additional $200 million in medium-term notes.
o On November 2, 1998, SCE&G redeemed, prior to maturity, all $30
million principal amount outstanding of its 7.25% Series First and
Refunding Mortgage Bonds due January 1, 2002.
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; however,
no such consent is 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 $250 million of unsecured promissory notes or commercial paper with
maturity dates of twelve months or less, but not later than December 31, 2001.
GENCO has not sought such authorization.
At December 31, 1998 SCE&G had $285 million of authorized lines of credit
which includes a credit agreement for a maximum of $250 million to support the
issuance of commercial paper. Unused lines of credit at December 31, 1998
totaled $285 million. SCE&G commercial paper outstanding at December 31, 1998
and December 31, 1997 was $125.2 million and $13.3 million, respectively. In
addition, Fuel Company had a credit agreement for a maximum of $125 million with
the full amount available at December 31, 1998. The credit agreement supports
the issuance of short-term commercial paper for the financing of nuclear and
fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial
paper outstanding at December 31, 1998 was $66.0 million.
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 twelve consecutive
months immediately preceding the month of issuance are at least one and one-half
times the aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended December 31, 1998 the
Preferred Stock Ratio was 2.27.
On January 26, 1998 an additional three million shares of SCANA common
stock were registered for sale under the SPSP. During 1998, approximately 1.3
million shares of SCANA's common stock were purchased on the open market for
issuance under the SPSP.
The Company anticipates that its 1999 cash requirements of $633 million
will be met through internally generated funds (approximately 51%, after payment
of dividends), and the incurrence of additional short-term and long-term
indebtedness. Sales of additional equity securities may also be made. The
Company expects that it has or can obtain adequate sources of financing to meet
its projected cash requirements for the next twelve months and for the
foreseeable future.
Environmental Matters
The Clean Air Act requires electric utilities to reduce emissions of
sulfur dioxide and nitrogen oxide substantially by the year 2000. These
requirements are being phased in over two periods. The first phase had a
compliance date of January 1, 1995 and the second, January 1, 2000. The
Company's facilities did not require modifications to meet the requirements of
Phase I. The Company will most likely meet the Phase II requirements through the
burning of natural gas and/or lower sulfur coal in its generating units and the
purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide
burners are being installed to reduce nitrogen oxide emissions to the levels
required by Phase II. Air toxicity regulations for the electric generating
industry are likely to be promulgated around the year 2000.
SCE&G and GENCO filed compliance plans with DHEC related to Phase II
sulfur dioxide requirements in 1995 and Phase II nitrogen oxide requirements in
1997. The Company currently estimates that air emissions control equipment will
require capital expenditures of $170 million over the 1999-2003 period to
retrofit existing facilities, with increased operation and maintenance cost of
approximately $18 million per year. To meet compliance requirements through the
year 2008, the Company anticipates total capital expenditures of approximately
$268 million.
On September 24, 1998, the United States Environmental Protection
Agency (EPA) issued its final regional nitrogen oxide state implementation plan
(SIP) call rule. The rule finds that 22 eastern states, including South
Carolina, and the District of Columbia are all contributing significantly to
ozone non-attainment in downwind states. In response to that finding, EPA is
requiring that those 22 states amend their SIP's to achieve significant
reductions in ozone emissions within those states, and has targeted primarily
utility sources for the application of more rigorous nitrogen oxide emissions
controls. A number of states, including South Carolina, and other parties,
including a utility coalition of which the Company is a member, have filed suit
in federal court to challenge the EPA rule. Should the rule be upheld, the
Company may be required to make significant capital expenditures to add
supplemental nitrogen oxide control technology to one or more of its fossil
generation plants.
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 program in monitoring and controlling thermal discharges and
strategies for toxicity reduction in wastewater streams. The Company has been
developing compliance plans for these initiatives.
In 1998 DHEC promulgated regulations for the disposal of industrial
solid waste as directed by the South Carolina Solid Waste Policy and Management
Act of 1991. The full impact of these regulations is not yet known; however,
they may significantly increase SCE&G's and GENCO's costs of construction and
operation of existing and future ash management facilities.
The Company has an environmental assessment program to identify and
assess current and former operations sites that could require environmental
cleanup. As site assessments are initiated, estimates are made of the
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations. Such amounts are deferred and
amortized with recovery provided through rates. The Company has also recovered
portions of its environmental liabilities through settlements with various
insurance carriers. As of December 31, 1998, the Company has recovered all
amounts previously deferred for its electric operations. The Company expects to
recover all deferred amounts related to its gas operations by December 2002.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $21.3 million and $32.4 million at December 31, 1998 and
1997, respectively. The deferral includes the estimated costs associated with
the matters discussed below.
o 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 encompasses approximately 30 acres and
includes properties which were locations for industrial operations,
including a wood preserving (creosote) plant, one of SCE&G's
decommissioned manufactured gas plants, properties owned by the
National Park Service and the City of Charleston, and private
properties. The site has not been placed on the National Priorities
List, but may be added in the future. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope of Work.
Field work began in November 1993, and the EPA approved a Remedial
Investigation Report in February 1997 and a Feasibility Study Report
in June 1998. In July 1998, the EPA approved SCE&G's Removal Action
Work Plan for soil excavation. SCE&G completed Phase One of the
Removal Action in 1998 at a cost of approximately $1.5 million. Phase
Two will include excavation and installation of several permanent
barriers to mitigate coal tar seepage. Phase Two began in November
1998, and is expected to cost approximately $2.2 million. On September
30, 1998 a Record of Decision was issued which sets forth the EPA's
view of the extent of each PRP's responsibility for site contamination
and the level to which the site must be remediated. On January 13,
1999 the EPA issued a Unilateral Administrative Order for Remedial
Design and Remedial Action directing SCE&G to design and carry out a
plan of remediation for the Calhoun Park site. The Order is
temporarily stayed pending further negotiations between SCE&G and the
EPA.
In October 1996 the City of Charleston and SCE&G settled all
environmental claims the City may have had against SCE&G involving the
Calhoun Park area for a payment of $26 million over four years
(1996-1999) by SCE&G to the City. SCE&G is recovering the amount of the
settlement, which does not encompass site assessment and cleanup costs,
through rates in the same manner as other amounts accrued for site
assessments and cleanup as discussed above. As part of the environmental
settlement, SCE&G has agreed to construct an 1,100 space parking garage
on the Calhoun Park site and to transfer the facility to the City in
exchange for a 20-year municipal bond backed by revenues from the
parking garage and a mortgage on the parking garage. The total amount of
the bond is not to exceed $16.9 million, the maximum expected project
cost. The parking garage is currently under construction and is
scheduled for completion in the spring of the year 2000.
o SCE&G owns three other decommissioned manufactured gas plant sites which
contain residues of by-product chemicals. For the site located in
Sumter, South Carolina, effective September 15, 1998, SCE&G entered into
a Remedial Action Plan Contract with DHEC pursuant to which it agreed to
undertake a full site investigation and remediation under the oversight
of DHEC. Site investigation and characterization are proceeding
according to schedule. Upon selection and successful implementation of a
site remedy, DHEC will give SCE&G a Certificate of Completion, and a
covenant not to sue. SCE&G is continuing to investigate the other two
sites, and is monitoring the nature and extent of residual
contamination.
Regulatory Matters
On December 11, 1998, the PSC issued an order requiring SCE&G to reduce
retail electric rates on a prospective basis. The PSC acted in response to SCE&G
reporting that it earned a 13.04% return on common equity for its retail
electric operations for the twelve months ended September 30, 1998. This return
on common equity exceeded SCE&G's authorized return of 12.0% by 1.04%, or $22.7
million, primarily as a result of record-breaking heat experienced during the
summer. The order requires prospective rate reductions on a per kilowatt-hour
basis, based on actual retail sales for the twelve months ended September 30,
1998. This action will reduce future reported return on common equity to the
Commission-authorized level if SCE&G experiences the same weather effect and
other business results as that of the twelve months ended September 30, 1998.
The order requires the rate reductions to be placed into effect with the first
billing cycle of January 1999. On December 21, 1998, SCE&G filed a motion for
reconsideration with the PSC. On January 12, 1999, the PSC denied SCE&G's motion
for reconsideration, ruled that no further rate action was required, and
reaffirmed SCE&G's return on equity of 12.0%.
On January 9, 1996 the PSC issued an order granting SCE&G an increase in
retail electric rates of 7.34%, which was designed to produce additional
revenues, based on a test year, of approximately $67.5 million annually. The
increase was implemented in two phases. The first phase, an increase in revenues
of approximately $59.5 million annually or 6.47%, commenced in January 1996. The
second phase, an increase in revenues of approximately $8.0 million annually, or
.87%, was implemented in January 1997. The PSC authorized a return on common
equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over a ten-year
period. Additionally, the PSC approved accelerated recovery of a significant
portion of SCE&G's electric regulatory assets (excluding deferred income tax
assets) and the remaining transition obligation for postretirement benefits
other than pensions, changing the amortization periods to allow recovery by the
end of the year 2000. SCE&G's request to shift, for ratemaking purposes,
approximately $257 million of depreciation reserves from transmission and
distribution assets to nuclear production assets was also approved. The Consumer
Advocate and two other intervenors appealed certain issues in the order
initially to the Circuit Court, which affirmed the PSC's decisions, and,
subsequently, to the Supreme Court. In March 1998, SCE&G, the PSC, the Consumer
Advocate and one of the other intervenors reached an agreement that provided for
the reversal of the shift in depreciation reserves and the dismissal of the
appeal of all other issues. The PSC also authorized SCE&G to adjust depreciation
rates that had been approved in the 1996 rate order for its electric
transmission, distribution and nuclear production properties to eliminate the
effect of the depreciation reserve shift and to retroactively apply such
depreciation rates to February 1996. As a result, a one-time reduction in
depreciation expense of $5.5 million after taxes was recorded in March 1998. The
agreement does not affect retail electric rates. The FERC had previously
rejected the transfer of depreciation reserves for rates subject to its
jurisdiction. In September 1998, the Supreme Court affirmed the Circuit Court's
rulings on the issues contested by the remaining intervenor.
On August 8, 1990, the PSC issued an order 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
appealed 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 Circuit Court decision and reinstated the
PSC order. 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. The PSC then held another
hearing and issued its order dated December 12, 1995 maintaining the present
level of the maximum markup on industrial sales ("cap"). This Order was appealed
to the Circuit Court by Pipeline Corporation and the industrial customer group
with several other parties intervening, including the Consumer Advocate of South
Carolina. On October 10, 1997, the Circuit Court issued an order in favor of the
Consumer Advocate and the industrial customer group and remanded the case to the
PSC to determine an overall rate of return for Pipeline Corporation. The Circuit
Court also issued a second order which ruled against Pipeline Corporation and
affirmed the PSC's decision that the cap should not be increased. Several
motions and appeals were filed subsequently at the Supreme Court. The Supreme
Court has dismissed the appeals of the PSC and Pipeline Corporation from the
first order without prejudice until the PSC completes proceedings on remand and
has held Pipeline Corporation's appeal of the second order in abeyance until the
PSC completes proceedings on remand. The remanded case was heard by the PSC in
June 1998. The PSC set an overall rate of return on equity for Pipeline
Corporation of 12.5-16.5%. The South Carolina Energy Users Committee (SCEUC)
appealed the order to the Circuit Court. Pipeline Corporation subsequently filed
a Motion to Dismiss the SCEUC's appeal on the grounds that it was not timely
filed. These cases should be heard in 1999.
The Company's regulated business operations were impacted by the NEPA
and FERC Orders No. 636 and 888. NEPA was 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. See "Competition" for a discussion of FERC
Order 888. Order No. 636 was 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
continues to be able to meet successfully the challenges of these altered
business climates and does not anticipate any material adverse impact on the
results of operations, cash flows, financial position or business prospects.
Year 2000 Issue
The Year 2000 is an issue because many computers, embedded systems and
software were originally programmed using two digits rather than four digits to
identify the applicable year. This may prevent them from accurately processing
information with dates beyond 1999. Because the Year 2000 issue could have a
material impact on the operations of the Company if not addressed, the Company's
goal is to be Year 2000 ready. This means that before the year 2000, critical
systems, equipment, applications and business relationships will have been
evaluated and should be suitable to continue into and beyond the year 2000 and
that applicable contingency plans are in place.
In 1993, SCANA began the first of several projects to replace many of
its business application systems to provide increased functionality and to
improve access to business information. Accordingly, SCANA has implemented new
general ledger, purchasing, materials inventory and accounts payable systems,
and is currently implementing a new customer information system. The new
customer information system is being phased into production by geographical
area, and should be fully implemented in the first half of 1999. These new
systems, which comprise a significant portion of SCANA's applications software,
are designed to be Year 2000 compliant, and therefore mitigate overall Year 2000
exposure.
In 1997, SCANA established a Corporate Year 2000 Project Office (Project
Office) to direct Year 2000 efforts throughout the Company. A Steering Committee
was formed to direct the efforts of the Project Office. The Steering Committee
reports to the senior officers of SCANA and to the board of directors. It is
chaired by the chief financial officer of SCANA and is comprised of officers
representing all operational areas. The Project Office is staffed by nine full
time project managers and extensive support personnel. The Project Office is
responsible for addressing Year 2000 issues and coordinating the required
assessment and remediation efforts.
SCANA's Year 2000 efforts encompass three projects, all reporting to the
Steering Committee. The Information Technology Project covers all mainframe and
client server application software, infrastructure hardware, system software,
desktop computers and network equipment. The Embedded Systems Project covers all
microprocessors, instruments and control devices, monitoring equipment on power
lines and in substations, security and control devices, telephone systems and
certain types of meters. The Procedures and External Interfaces Project covers
Year 2000 procedures, documentation and communications with key suppliers,
vendors, customers, financial institutions and governmental agencies.
SCANA's Year 2000 project approach involves the following: (1)
inventorying all Year 2000 internal and external items and entities and updating
the Year 2000 Inventory Database; (2) performing risk analysis and corporate
prioritization of all inventory entries; (3) performing detailed assessments of
all inventory entries to determine Year 2000 readiness and establishing a
remediation action plan where necessary; (4) remediating all inventory entries
assessed as non-compliant, including repairing, replacing or developing
acceptable work-arounds; (5) testing through date simulation and comprehensive
test data; (6) implementation of all converted systems and equipment into
production operations; and (7) contingency planning.
Detailed project plans exist for each of the Year 2000 projects. These
project plans, work schedules and resource requirements are reviewed weekly by
the project managers and monthly by the Steering Committee. The Year 2000
projects, which will address the Company's critical systems and business
relationships, are appropriately staffed and are currently on schedule to be
completed by July 1999. As reported to the North American Electric Reliability
Council (NERC) in January 1999, the Company was 100% complete with inventory
tasks, 63% complete with detailed assessment tasks and 58% complete with
remediation tasks.
The Information Technology Project Team has completed the assessment and
initial code remediation for all application software. Many of the applications
have been tested in an isolated Year 2000 testing environment and the rest are
being tested according to the project schedule. The assessment of the technical
infrastructure and desktop computing environment is complete and required
remediation is in process. Testing of all network equipment is in process. The
Information Technology Project was approximately 55% complete through December
1998.
The Embedded Systems Project Team, which includes approximately 20
engineers with prior experience with microprocessors, was formed, and detailed
assessment, remediation and testing procedures were developed. This team is
currently working closely with each of SCANA's business units to complete the
assessments of critical systems and equipment based on the corporate
prioritization process. An Embedded Systems Audit Review Committee has been
established to review all assessments for critical systems. As assessments are
completed, any required remediation efforts are evaluated and implemented.
Independent verifications for selected completed assessments are planned during
the first quarter of 1999. The Embedded Systems Project was approximately 50%
complete through December 1998.
The Procedures and External Interfaces Project Team has developed
written documentation and procedures for Year 2000 compliance definition,
document control, inventory, prioritization, assessment, remediation, change
control, business continuity planning, and vendor and supplier communications.
This team is coordinating communications with all significant vendors and
suppliers in an attempt to determine the extent to which the Company may be
vulnerable to their failure to remediate their own Year 2000 issues. The Company
has completed an initial survey of vendors and is currently evaluating the
responses to the survey and conducting additional inquiries where necessary. The
Company is also in the process of evaluating critical third party service
providers to ascertain their Year 2000 readiness. The Company has developed
communications materials explaining its year 2000 efforts and is continuing
communications with significant customers and external groups, including the
South Carolina and Georgia Public Service Commissions. The Procedures and
External Interfaces Project was approximately 45% complete through December
1998.
The Company's projected total cost of its Year 2000 efforts and the
anticipated timing and breakdown of those expenditures, is as follows:
------------------- -------------- ------------------ ----------------
Internal Out of Pocket Total
------------------- -------------- ------------------ ----------------
(Millions of Dollars)
Project To Date $ 2 $ 6 $ 8
1999 3 9 12
----- - ------- ----
Total $ 5 $ 15 $20
------------------- -------------- ------------------ ----------------
The cost of the project is based on management's best estimates, which
are based on assumptions regarding future events. These future events include
continued availability of key resources, third parties' Year 2000 readiness and
other factors. The cost of the project is not expected to have a material impact
on the results of operations or on the financial position or cash flows of SCANA
or SCE&G. The costs of implementing the new business application systems
referred to earlier are not included in these cost estimates.
A failure to correct a material Year 2000 problem by the Company or by a
critical third party supplier could result in an interruption in, or a failure
of the Company's ability to provide energy services. At this time, the Company
believes its most reasonably likely worst case scenario is that Year 2000
failures could lead to temporary reduced generating capacity on the Company's
electrical grid, temporary intermittent interruptions in communications and
temporary intermittent interruptions in gas supply from interstate suppliers or
producers. A Year 2000 problem of this nature could result in temporary
interruptions in electric or gas service to customers. The Company has no
historical experience with interruptions caused by this scenario. However, these
temporary interruptions in service, if any, might be similar to weather-related
outages that the Company encounters from time to time in its business today.
Although the Company does not believe that this scenario will occur, the Company
is enhancing existing contingency plans to ensure preparedness and to mitigate
the long term effect of such a scenario. Since the expected impact of this
scenario on the Company's operations, cash flow and financial position cannot be
determined, there is no assurance that it would not be material.
The Company has established eight business continuity planning task
groups to develop Year 2000 business continuity plans. These task groups have
developed initial draft plans to cover the Company's Corporate Operations,
Customer Service Operations, Electric Generation, Transmission and Distribution
Operations, Gas Delivery Operations, Telecommunications and Emergency
Preparedness, Information Technology and Procurement. Detailed contingency plans
that were already in place to cover weather-related outages, computer failures
and generation outages were used and/or referenced as the basis for the initial
draft Year 2000 business continuity plans. The initial draft plans are
continuing to be enhanced, and where necessary, new plans will be developed to
include mitigation strategies and emergency response action plans to address
potential Year 2000 scenarios and critical system failures. The final plans will
also include mitigation strategies to address reliance on critical suppliers.
NERC is coordinating Year 2000 efforts of the electric utility industry
in the United States and contingency planning within the regional electric
reliability councils. Coordination in SCE&G's region is through the Southeastern
Electric Reliability Council (SERC). SCE&G's contingency planning efforts are in
compliance with the SERC and NERC contingency planning guidelines which required
draft contingency plans to be complete by December 31, 1998 and will require
final contingency plans to be complete by June 30, 1999.
In addition to NERC and SERC, SCE&G is working with the Electric Power
Research Institute to address the issue of overall grid reliability and
protection. To ensure that all Year 2000 issues at its Summer Station nuclear
plant are addressed, SCE&G is closely cooperating with other utility companies
that own nuclear power plants. The utilities are sharing technical nuclear plant
operating and monitoring systems information to ensure the prompt and effective
resolution of the year 2000 issue.
Other Matters
On December 1, 1997, Petroleum Resources sold substantially all of its
assets for $110 million. The resulting gain of $17.6 million was recorded in
"Other Income." Proceeds from the sale were used to repurchase approximately 3.7
million shares of SCANA's outstanding common stock through open market purchases
and through privately negotiated transactions. All of the repurchased shares
were retired, reducing the number of shares issued and outstanding.
Investments in Equity Securities
The Company, through a subsidiary (SCI), has made significant
investments in the equity securities of various telecommunications companies.
The performance of these investments is subject to a number of risks and
uncertainties. Important factors that impact the performance of these
investments include continuing rapid and significant changes in technology,
increasingly intense competition and changing consumer preferences and
expectations, among others.
At December 31, 1998, SCI held the following investments in ITC Holding
Company (ITC) and its affiliates:
o Powertel, Inc. (Powertel) is a publicly traded company that owns and
operates PCS systems in several major Southeastern markets. SCI owns
approximately 4.6 million common shares of Powertel at a cost of
approximately $68.0 million. Common shares were initially recorded at
$14.85 per share, and closed at $13.5625 on December 31, 1998,
resulting in a pre-tax unrealized holding loss of $5.8 million. The
after-tax amount of such loss is included in the balance sheet as a
component of "Common Equity." On June 30, 1998, SCI purchased 50,000
shares of non-voting 6.5% series E convertible preferred stock of
Powertel. In addition, SCI owns the following series of non-voting
convertible preferred shares, at the approximate cost noted: 100,000
shares series B ($75.1 million) and 50,000 shares series D ($22.5
million). Preferred series B shares are convertible in March 2002 at a
conversion price of $16.50 per common share or approximately 4.5
million common shares. Preferred series D shares are convertible in
March 2002 at a conversion price of $12.75 per common share or
approximately 1.7 million common shares. Preferred series E shares are
convertible in June 2003 at a conversion price of $22.01 per common
share or approximately 3.4 million common shares. The market value of
the convertible preferred shares of Powertel is not readily
determinable. However, on an as converted basis, the market value of
the underlying common shares for the preferred shares was
approximately $131.8 million at December 31, 1998, resulting in an
unrecorded pre-tax holding loss of $40.8 million. On September 15,
1998, SCI received 113,656 shares of Powertel Common Stock as its
quarterly dividend on the preferred series E investment.
o ITC Delta^Com, Inc. (ITCD) is a fiber optic telecommunications
provider. On November 9 1998, SCI purchased 500,000 common shares of
ITCD at a cost of $14.50 per share. Prior to this SCI owned
approximately 3.6 million common shares of ITCD (after giving effect
to a two-for-one stock split announced July 29, 1998) at a cost of
approximately $9 million. ITCD common stock closed at $15.25 per share
on December 31, 1998, resulting in a pre-tax unrealized holding gain
of $45.6 million. The after-tax amount of such gain is included in the
balance sheet as a component of "Common Equity." In addition, SCI owns
1,480,771 shares of series A preferred stock of ITCD at a cost of
approximately $11.2 million. Series A preferred shares are convertible
in March 2002 into 2,961,542 shares of ITCD common stock (after giving
effect to the two-for-one stock split). The market value of series A
preferred stock of ITCD is not readily determinable. However, on an as
converted basis the market value of the underlying common stock for
the series A preferred stock was approximately $45.2 million at
December 31, 1998, resulting in an unrecorded pre-tax holding gain of
$33.9 million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of cable,
television, telephone and internet services. SCI owns 71,050 units of
Knology. Each unit consists of one 11.875% Senior Discount Note due 2007
and one warrant entitling the holder to purchase .003734 shares of
preferred stock of Knology. The cost of this investment was approximately
$40 million. SCI also owns an additional 753 warrants which entitles it to
purchase 753 shares of preferred stock at $1,500 per share. Effective July
31, 1998, SCI sold all of its 3,639 shares of preferred stock in Knology to
ITC. For each preferred share sold, SCI received $1,600 of ITC series B
convertible preferred shares, for a total of 133,664 shares. SCI also
received approximately $0.4 million in cash. SCI's original investment in
these shares was approximately $5.3 million.
o ITC has an ownership interest in several Southeastern communications
companies. SCI owns approximately 3.1 million common shares (after giving
effect to a four-for-one stock split on August 25, 1998), 645,153 series A
convertible preferred shares, and 133,664 series B convertible preferred
shares of ITC. These investments cost approximately $7.1 million, $8.9
million, and $5.0 million, respectively. Series A and series B preferred
shares are convertible in March 2002 into ITC common shares at a conversion
price of $13.45 and $43.56, respectively, on a four to one basis. The
market value of these investments is not readily determinable.
Subsequent Events
On February 17, 1999, SCANA and Public Service Company of North
Carolina, Inc. (PSNC) announced a definitive agreement whereby SCANA will
acquire PSNC in a transaction valued at approximately $900 million, including
the assumption of debt. The transaction will be accounted for as a purchase. It
is anticipated that PSNC will be operated as a wholly-owned subsidiary of SCANA.
Completion of the transaction is subject to the approval of the shareholders of
both companies and applicable regulatory approvals. It is anticipated that the
approval process can be completed by the end of 1999.
On February 17, 1999, the Board of Directors also announced the
adoption of a new common stock dividend policy to bring the Company's dividend
payout ratio more in line with that of growth-oriented utilities. Under the new
policy, the board anticipated declaring the current dividend of $0.385 cents per
share payable July 1, 1999 and reducing the dividend to $0.275 per share,
effective with the dividend to be paid thereafter. This action would make the
Company's indicated annual dividend rate on common stock $1.10 per share.
On March 9, 1999, SCE&G issued $100 million First Mortgage Bonds due
March 1, 2009 at an interest rate of 6.125%. The funds were used to reduce
short-term debt.
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 1996 through 1998 were as follows:
1998 1997 1996
- --------------------------------------------------------------------------
Earnings per weighted average share $2.12 $2.06 $2.05
Percent increase in earnings
per share 2.9% 0.5% 20.6%
Return earned on common equity 12.8% 12.3% 12.8%
- --------------------------------------------------------------------------
o 1998 Earnings per share and return on common equity increased primarily as
a result of more favorable weather and customer growth, which more than
offset higher operating costs in 1998 and the gain from the sale of oil and
gas properties in 1997. In addition, net income for 1998 includes a
one-time, after-tax reduction to depreciation rates retroactive to February
1996. This change in rates results from the reversal of a $257 million
shift in depreciation reserves from electric transmission and distribution
assets to nuclear production assets, previously approved in a PSC rate
order in January 1996. See "Liquidity and Capital Resources."
o 1997 Earnings per share and return on common equity increased primarily as
a result of the $17.6 million after-tax gain on the sale of the oil and gas
properties of Petroleum Resources and higher gas sales margins. These
increases more than offset increases in operating expenses and the
reduction to other income from the 1996 after-tax gain reported by SCI as a
result of a business combination of Powertel.
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 4.4% of income
before income taxes in 1998, 4.0% in 1997 and 3.9% in 1996.
In 1998 SCANA's Board of Directors raised the quarterly cash dividend
on common stock to 38 1/2 cents per share from 37 3/4 cents per share. The
increase, effective with the dividend payable on April 1, 1998, raised the
indicated annual dividend rate to $1.54 per share from $1.51. See additional
discussion of the Company's dividend policy at Subsequent Events.
On December 1, 1997, Petroleum Resources sold substantially all of its
assets for $110 million. The resulting after-tax gain of $17.6 million was
recorded in "Other Income."
Electric Operations
Electric operations sales margins for 1998, 1997 and 1996 were as
follows:
1998 1997 1996
- ---------------------------------------------------------------------------
(Millions of Dollars)
Operating revenues $1,219.8 $1,103.0 $1,106.5
Less: Fuel used in generation 262.3 248.4 250.5
Purchased power 31.5 9.4 11.4
- ---------------------------------------------------------------------------
Margin $ 926.0 $ 845.2 $ 844.6
===========================================================================
o 1998 The sales margin increased for 1998 primarily due to morefavorable
weather and customer growth.
o 1997 The sales margin increased slightly due to the favorable
impact of the rate increase placed into effect in January 1997 and
economic growth factors which were offset by the effect of milder
weather.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes were as follows:
Classification 1998 1997
- -----------------------------------------------------------------------
Residential 676,578 (292,518)
Commercial 578,290 100,324
Industrial 389,931 113,717
Sales for Resale (excluding interchange) 65,367 36,894
Other 29,823 15
- ------------------------------------------------------------------------
Total territorial 1,739,989 (41,569)
Negotiated Market Sales Tariff 610,784 (10,818)
=======================================================================
Total 2,350,773 (52,387)
=======================================================================
o 1998 The sales volume increases for 1998 were primarily due to morefavorable
weather and customer growth.
o 1997 The sales volume for residential sales decreased for 1997 as a result of
milder weather.
Gas Distribution
Gas distribution sales margins for 1998, 1997 and 1996 were as follows:
1998 1997 1996
- ----------------------------------------------------------------------
(Millions of Dollars)
Operating revenues $230.4 $233.6 $234.8
Less: Gas purchased for resale 142.4 151.9 157.1
- ----------------------------------------------------------------------
Margin $ 88.0 $ 81.7 $ 77.7
======================================================================
o 1998The sales margin increased over 1997 due to renegotiation of
industrial customers' contracts, lower gas prices and increased
sales to electric generation facilities.
o 1997 The sales margin increased over the prior year primarily as a
result of increases in contract prices and sales to industrial
interruptible customers.
Increases (decreases) from the prior year in dekatherm (DT) sales
volume by classes, including transportation gas, were as follows:
Classification 1998 1997
- ----------------------------------------------------------------------
Residential (2,685) (2,188,215)
Commercial 389,468 (123,385)
Industrial 2,363,341 1,820,166
Transportation gas (673,795) (430,610)
- --------------------------------------------------------------------- -
Total 2,076,329 (922,044)
=====================================================================
o 1998 The sales volume for commercial and industrial customers
increased, and transportation decreased, for 1998 as a result of
lower gas prices and increased sales to electric generation
facilities.
o 1997 The sales volume for residential customers decreased for 1997
as a result of milder weather which was partially offset by
increases in sales to industrial interruptible customers.
Gas Transmission
Gas transmission sales margins for 1998, 1997 and 1996 were as follows:
1998 1997 1996
- ----------------------------------------------------------------------
(Millions of Dollars)
Operating revenues $329.8 $339.9 $326.6
Less: Gas purchased for resale 276.7 289.3 279.6
- ----------------------------------------------------------------------
Margin $ 53.1 $ 50.6 $ 47.0
======================================================================
o 1998 The sales margin increased over 1997 primarily as a result of
increased sales to electric generation facilities.
o 1997 The sales margin increased over the prior year primarily as a result
of higher margins on sales to industrial interruptible customers. The
higher margins were attributable to fewer curtailments due to higher
system capacity from a pipeline expansion completed in late 1996.
Increases (decreases) from the prior year in dekatherms (DT) sales volume
by classes including transportation gas were as follows:
Classification 1998 1997
- -----------------------------------------------------------------------
Commercial 9,799 4,056
Industrial 5,238,940 5,690,034
Transportation (695,921) (523,291)
Sale for resale 314,895 673,205
- ----------------------------------------------------------------------
Total 4,867,713 5,844,004
=======================================================================
o 1998 The sales volume for industrial customers increased, and
transportation decreased, for 1998 as a result of lower gas prices
and increased sales to electric generation facilities. Sales for
resale increased due to lower gas prices.
o 1997 The sales volume for industrial customers increased, and
transportation decreased, for 1997 as a result of fewer
curtailments due to higher system capacity from a pipeline
expansion completed in late 1996.
Energy Marketing
Energy marketing sales margins for 1998, 1997 and 1996 were as follows:
1998 1997 1996
- -----------------------------------------------------------------------
(Millions of Dollars)
Operating revenues $568.1 $205.9 $261.4
Less: Gas and electricity
purchased for resale 569.8 203.3 253.4
- ------------------------------------------------------------------------
Margin $ (1.7) $ 2.6 $ 8.0
=======================================================================
o 1998 The sales margin decreased for 1998 primarily due to losses on
energy trading and continued mild weather.
o 1997 The sales margin decreased for 1997 primarily due to mild weather.
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including taxes,
were as follows:
Classification 1998 1997
- -------------------------------------------------------------------------
(Millions of Dollars)
Other operation and maintenance $31.1 $ 3.1
Depreciation and amortization (8.2) 5.5
Income taxes 30.7 (12.5)
Other taxes 5.7 8.6
- ------------------------------------------------------------------------
Total $59.3 $ 4.7
=========================================================================
o 1998 Other operating and maintenance expenses increased over 1997 primarily
due to increased maintenance costs for electric generating and distribution
facilities, various other electric operating costs and Year 2000 testing
and remediation. The decrease in depreciation and amortization expense
reflects the non-recurring adjustment to depreciation expense discussed
under earnings and dividends. The increase in income tax expense primarily
reflects changes in operating income. The increase in other taxes primarily
results from increased property taxes.
o 1997 Other operation and maintenance expenses increased somewhat from 1996
levels. A decrease in transit operating costs resulting from the Company's
transfer of the ownership of the Charleston transit system to the City of
Charleston in October 1996 largely offset increases in costs at electric
generating plants and other operating costs. The increase in depreciation
and amortization expenses for 1997 reflects the additions to
plant-in-service. The change in income tax expense is primarily due to
changes in pre-tax operating income and the difference between estimated
income taxes accrued and actual income tax expense per the tax returns as
filed. The increase in other taxes results primarily from the accrual of
additional property taxes, beginning in January 1997, related to the Cope
plant and other property additions which was partially offset by a
reduction in the 1997 property tax assessment. Recovery of the Cope Plant
property taxes is provided for in a retail electric rate increase that
became effective January 1997.
Other Income
o 1998Other income, net of taxes, decreased approximately $25.1
million, primarily as a result of the gain on the sale of
Petroleum Resources recorded in 1997. In addition, lower earnings
from non-regulated businesses, primarily losses from energy
marketing activities, resulted from decreased gas margins,
volatility in power markets related to unusually hot summer
weather and startup costs in new markets.
o 1997Other income, net of taxes, increased approximately $8.5
million. The primary factors accounting for the change in other
income were the Petroleum Resources gain on the sale of oil and
gas properties in 1997, offset by the gain reported by SCI in 1996
referred to under "Earnings and Dividends" and which is included
in other income reported for 1996.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component
of AFC, were as follows:
Classification 1998 1997
- -------------------------------------------------------------------------
(Millions of Dollars)
Interest on long-term debt, net $ 5.4 $ 1.1
Other interest expense (1.8) (1.5)
- -------------------------------------------------------------------------
Total $ 3.6 $(0.4)
=========================================================================
o 1998 Interest expense increased over 1997 as a result of the issuance
of medium-term notes in the third quarter of 1998.
o 1997 There was no material change in interest expense.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations, the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
December 31, 1998
Expected Maturity Date
(Millions of Dollars)
There- Fair
Liabilities 1999 2000 2001 2002 2003 after Total Value
----------------------------------------------------------------
Long-Term Debt:
Fixed Rate ($) 106.5 213.5 27.5 27.5 284.4 1,165.8 1,789.5 1,869.1
Average Interest Rate 6.86 5.93 6.87 6.87 6.29 7.47 7.04
While a decrease in interest rates would increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.
In addition, the Company has invested in a telecommunications company
approximately $40 million for 11.875% senior discount notes due 2007. The fair
value of these notes approximates cost. An increase in market interest rates
would result in a decrease in fair value of these notes and a corresponding
adjustment, net of tax, to other comprehensive income.
Equity price risk - Investments in telecommunications companies' marketable
equity securities are carried at their market value of $375.1 million, in
accordance with Statement of Financial Accounting Standards No. 115. A ten
percent decline in market value would result in a $37.5 million reduction in
fair value and a corresponding adjustment, net of tax effect, to the related
equity account for unrealized gains/losses.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditors' Report............................................ 41
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1998 and 1997............ 42
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1998, 1997 and 1996..................... 44
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996... 45
Consolidated Statements of Capitalization as of
December 31, 1998 and 1997.................... 46
Consolidated Statements of Changes in Common Equity for the years ended
December 31, 1998 and 1997.......................................... 48
Notes to Consolidated Financial Statements............................. 49
Information required to be disclosed in supplemental financial statement
schedules is included in the consolidated financial statements or in the notes
thereto.
INDEPENDENT AUDITORS' REPORT
SCANA Corporation:
We have audited the accompanying Consolidated Balance Sheets, Statements of
Capitalization and Statements of Changes in Common Equity of SCANA Corporation
and subsidiaries (Company) as of December 31, 1998 and 1997 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, 1998. 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, 1998
and 1997, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, SC
February 8, 1999
(February 17, 1999 as to Note 13)
SCANA Corporation
CONSOLIDATED BALANCE SHEETS
December 31, 1998 1997
ASSETS (Millions of Dollars)
Utility Plant (Notes 1, 3 & 4):
Electric $4,406 $4,292
Gas 604 580
Other 175 84
- -------------------------------------------------------------------------------------------
Total 5,185 4,956
Less accumulated depreciation and amortization 1,728 1,619
- -------------------------------------------------------------------------------------------
Total 3,457 3,337
Construction work in progress 251 234
Nuclear fuel, net of accumulated amortization 56 53
Acquisition adjustment-gas, net of accumulated amortization 23 24
- -------------------------------------------------------------------------------------------
Utility Plant, Net 3,787 3,648
- -------------------------------------------------------------------------------------------
Nonutility Property and Investments (net of accumulated
depreciation and depletion)(Note 1) 493 364
- -------------------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments (Note 8) 62 60
Receivables 276 248
Inventories (At average cost):
Fuel (Notes 3 & 4) 63 51
Materials and supplies 56 52
Prepayments 22 16
Deferred income taxes 22 25
- -------------------------------------------------------------------------------------------
Total Current Assets 501 452
- -------------------------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 22 32
Nuclear plant decommissioning fund (Note 1) 56 49
Pension asset, net (Note 1) 115 82
Other (Notes 1 & 10) 276 274
- -------------------------------------------------------------------------------------------
Total Deferred Debits 500 468
- -------------------------------------------------------------------------------------------
Total $5,281 $4,932
===========================================================================================
PAGE
December 31, 1998 1997
CAPITALIZATION AND LIABILITIES (Millions of Dollars)
Stockholders' Investment:
Common Equity (Note 5) $1,746 $1,788
Preferred stock (Not subject to purchase or sinking funds) 106 106
- -------------------------------------------------------------------------------------------
Total Stockholders' Investment 1,852 1,894
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 & 8) 11 12
SCE&G-Obligated Mandatorily Redeemable Preferred
Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50
million principal amount of the 7.55%
Junior Subordinated Debentures of SCE&G, due 2027 50 50
Long-Term Debt, Net (Notes 3, 4 & 8) 1,623 1,566
- -------------------------------------------------------------------------------------------
Total Capitalization 3,536 3,522
- -------------------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings (Notes 8 & 9) 195 59
Current portion of long-term debt (Note 3) 107 73
Accounts payable 219 131
Customer deposits 18 18
Taxes accrued 72 59
Interest accrued 28 26
Dividends declared 42 43
Other 13 14
- -------------------------------------------------------------------------------------------
Total Current Liabilities 694 423
- -------------------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes (Notes 1 & 7) 628 612
Deferred investment tax credits (Notes 1 & 7) 108 98
Reserve for nuclear plant decommissioning (Note 1) 56 49
Postretirement benefits 87 61
Other (Note 1) 172 167
- -------------------------------------------------------------------------------------------
Total Deferred Credits 1,051 987
- -------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 10) - -
- -------------------------------------------------------------------------------------------
Total $5,281 $4,932
===========================================================================================
See Notes to Consolidated Financial Statements.
PAGE
SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------
(Millions of Dollars
except per share amounts)
Operating Revenues (Notes 1 & 2):
Electric $1,220 $1,103 $1,107
Gas 411 419 403
Transit 1 1 3
- ------------------------------------------------------------------------------------------
Total Operating Revenues 1,632 1,523 1,513
- ------------------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 262 248 251
Purchased power 31 9 11
Gas purchased for resale 269 287 277
Other operation (Note 1) 257 239 239
Maintenance (Note 1) 84 72 68
Depreciation and amortization (Note 1) 145 153 148
Income taxes (Notes 1 & 7) 136 105 118
Other taxes 103 96 87
- ------------------------------------------------------------------------------------------
Total Operating Expenses 1,287 1,209 1,199
- ------------------------------------------------------------------------------------------
Operating Income 345 314 314
- ------------------------------------------------------------------------------------------
Other Income (Note 1):
Other income, net of income taxes 5 13 22
Gain on sale of subsidiary assets, net of income taxes - 18 -
Allowance for equity funds used during construction 8 7 7
- ------------------------------------------------------------------------------------------
Total Other Income 13 38 29
- ------------------------------------------------------------------------------------------
Income Before Interest Charges
and Preferred Stock Dividends 358 352 343
- ------------------------------------------------------------------------------------------
Interest Charges (Credits):
Interest on long-term debt, net 121 115 115
Other interest expense 10 12 13
Allowance for borrowed funds used
during construction (Note 1) (8) (6) (6)
- ------------------------------------------------------------------------------------------
Total Interest Charges, Net 123 121 122
- ------------------------------------------------------------------------------------------
Income Before Preferred Dividend Requirements
on Mandatorily Redeemable Preferred Securities 235 231 221
Preferred Dividend Requirement of SCE&G
- Obligated Mandatorily Redeemable
Preferred Securities 4 1 -
- ------------------------------------------------------------------------------------------
Income Before Preferred Stock Cash
Dividends of Subsidiary 231 230 221
Preferred Stock Cash Dividends of
Subsidiary (At stated rates) (8) (9) (6)
- ------------------------------------------------------------------------------------------
Net Income 223 221 215
Retained Earnings at Beginning of Year 617 558 498
Common Stock Cash Dividends Declared (Note 5) (162) (162) (155)
- ------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 678 $ 617 $ 558
==========================================================================================
Net Income $ 223 $ 221 $ 215
Weighted Average Number of Common Shares
Outstanding (Millions) 105.3 107.1 105.1
Earnings Per Weighted Average Share of
Common Stock (Basic and Diluted) $2.12 $2.06 $2.05
==========================================================================================
See Notes to Consolidated Financial Statements.
PAGE
SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $223 $221 $215
Adjustments to reconcile net income to net cash provided from operating
activities:
Depreciation, depletion and amortization 152 176 183
Amortization of nuclear fuel 20 19 19
Deferred income taxes, net 15 30 34
Pension asset (33) (24) (23)
Postretirement benefits 26 24 16
Allowance for funds used during construction (16) (13) (13)
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (28) 1 (28)
(Increase) decrease in inventories (16) 15 (8)
Increase (decrease) in accounts payable 88 (26) 19
Increase (decrease) in taxes accrued 13 (12) 4
Other, net 23 1 (17)
- ----------------------------------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 467 412 401
- ---------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures,
net of AFC (281) (250) (235)
(Increase) decrease in nonutility property and investments:
Sale of oil and gas producing properties - 110 53
Nonutility property (22) (38) (37)
Investments (106) (75) (85)
Sale of real estate assets - 8 2
- ---------------------------------------------------------------------------------------------------------
Net Cash Used For Investing Activities (409) (245) (302)
- ----------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of notes and loans 249 86 64
Issuance of SCE&G - obligated mandatorily redeemable
trust preferred securities - 49 -
Issuance of preferred stock - 99 -
Issuance of common stock - 29 69
Repayments:
Common stock (110) - -
Mortgage bonds (50) (15) (22)
Notes and loans (96) (70) (69)
Other long-term debt - (8) -
Preferred stock (1) (53) (3)
Dividend payments:
Common stock (163) (160) (153)
Preferred stock (7) (9) (5)
Short-term borrowings, net 136 (86) 32
Fuel financings, net (14) 14 (11)
- ----------------------------------------------------------------------------------------------------------
Net Cash Used For Financing Activities (56) (124) (98)
- ----------------------------------------------------------------------------------------------------------
Net Increase in Cash and Temporary Cash Investments 2 43 1
Cash and Temporary Cash Investments, January 1 60 17 16
- ---------------------------------------------------------------------------------------------------------
Cash and Temporary Cash Investments, December 31 $ 62 $ 60 $ 17
=========================================================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (Includes capitalized interest of
$7, $6 and $6) $127 $124 $126
- Income taxes 114 113 115
Noncash Financing Activities:
Unrealized gain on securities
available for sale (net of tax) 7 18 -
Charleston Franchise Agreement - - 21
Charleston Environmental Agreement - - 20
See Notes to Consolidated Financial Statements.
PAGE
SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1998 1997
- ------------------------------------------------------------------------------------------------------
(Millions of Dollars)
Common Equity (Note 5):
Common stock, without par value, authorized 150,000,000 shares; issued
and outstanding, 1998 - 103,572,623 shares and 1997 -107,321,113 shares $1,043 $1,153
Unrealized gain on securities available for sale 25 18
Retained earnings 678 617
- ------------------------------------------------------------------------------------------------------
Total Common Equity 1,746 50% 1,788 51%
- ------------------------------------------------------------------------------------------------------------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds):
$100 Par Value - Authorized 1,200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Series 1998 1997
$100 Par 6.52% 1,000,000 1,000,000 100.00 100 100
$50 Par 5.00% 125,209 125,209 52.50 6 6
- ------------------------------------------------------------------------------------------------------
Total Preferred Stock (Not subject to purchase or sinking funds) 106 3% 106 3%
- ------------------------------------------------------------------------------------------------------------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 & 8):
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 1998 and 1997
$50 Par Value - Authorized 1,580,052 shares
Shares Outstanding Redemption Price
Series 1998 1997
4.50% 12,800 14,400 51.00 1 1
4.60%(A) 20,052 21,894 51.00 1 1
4.60%(B) 64,600 68,000 50.50 3 4
5.125% 69,000 70,000 51.00 3 3
6.00% 73,600 76,800 50.50 4 4
-------------------
Total 240,052 251,094
===================
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1998 and 1997
Total Preferred Stock (Subject to purchase or sinking funds) 12 13
Less: Current portion, including sinking fund requirements 1 1
- ------------------------------------------------------------------------------------------------------
Total Preferred Stock, Net (Subject to purchase or sinking funds) 11 - 12 -
- -----------------------------------------------------------------------------------------------------------
SCE&G-Obligated Mandatorily Redeemable, Preferred Securities of SCE&G's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55% Junior Subordinated Debentures
of SCE&G, due 2027 50 1% 50 1%
- ------------------------------------------------------------------------------------------------------------
December 31, 1998 1997
- ---------------------------------------------------------------------------------------------
Long-Term Debt (Notes 3, 4 and 8): (Millions of Dollars)
SCANA Corporation:
Bank Notes, due 1998 - 60
Medium-Term Notes:
Year of
Series Maturity
5.76% 1998 - 20
7.17% 1999 43 43
6.60% 1999 30 30
6.15% 2000 20 20
6.51% 2003 20 20
6.90% 2007 25 25
6.05% 2003 60 -
6.25% 2003 75 -
5.81% 2008 115 -
South Carolina Electric & Gas Company:
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100 100
6 1/4% 2003 100 100
7.70% 2004 100 100
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
First and Refunding Mortgage Bonds:
Year of
Series Maturity
6 1/2% 1998 - 20
7 1/4% 2002 - 30
9% 2006 131 131
8 7/8% 2021 114 114
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984, due 2014 (6.50%) 57 57
Orangeburg County Series 1994, due 2024 (5.70%) 30 30
Other 16 16
Charleston Franchise Agreement due 1997-2002 14 18
Charleston Environmental Agreement due 1997-1999 6 13
South Carolina Generating Company, Inc.:
Berkeley County Pollution Control
Facilities Revenue Bonds, Series 1984 due 2014 (6.50%) 36 36
Note, 7.78%, due 2011 53 56
South Carolina Fuel Company, Inc. Commercial Paper 66 80
South Carolina Pipeline Corporation Notes, 6.72%, due 2013 19 20
Other 3 4
- ---------------------------------------------------------------------------------------------
Total Long-Term Debt 1,733 1,643
Less - Current maturities, including sinking
fund requirements 107 73
- Unamortized discount 3 4
- ---------------------------------------------------------------------------------------------
Total Long-Term Debt, Net 1,623 46% 1,566 45%
- --------------------------------------------------------------------------------------------
Total Capitalization $3,536 100% $3,522 100%
============================================================================================
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 1998 1997
- --------------------------------------------------------------------------------
Common Comprehensiv eCommon Comprehensive
Equity Income Equity Income
(Millions of Dollars)
Retained Earnings:
Balance at January 1 $ 617 $ 558
Net Income 223 $223 221 $221
Dividend declared on common stock (162) (162)
------ ------
Balance at December 31 678 617
------ ------
Accumulated other comprehensive income:
Balance at January 1 18 -
Unrealized gains on securities, net
of taxes ($4 and $11 in 1998
and 1997, respectively) 7 7 18 18
------ ---- ------ ----
Comprehensive income $230 $239
==== ====
Balance at December 31 25 18
------ ------
Common Stock:
Balance at January 1 1,153 1,125
Shares issued - 28
Shares repurchased (110) -
------ ------
Balance at December 31 1,043 1,153
------ ------
Total Common Equity $1,746 $1,788
====== ======
Accumulated other comprehensive income at December 31, 1998 and 1997 was
comprised of unrealized holding gains on securities, net of taxes. Net income
reported for the years ended December 31, 1998 and 1997 does not include any
realized gains or losses from securities.
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 Company, through
wholly owned subsidiaries, is engaged predominately in the generation and sale
of electricity to wholesale and retail customers in South Carolina and in the
purchase, sale and transportation of natural gas to wholesale and retail
customers in South Carolina. The Company is also engaged in other energy-related
businesses, such as the marketing of natural gas in Georgia's newly deregulated
natural gas market. The Company has investments in telecommunications companies
and provides fiber optic communications in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts
of the Company and its wholly owned subsidiaries:
Regulated utilities
South Carolina Electric & Gas Company (SCE&G)
South Carolina Fuel Company, Inc. (Fuel Company)
South Carolina Generating Company, Inc. (GENCO)
South Carolina Pipeline Corporation (Pipeline Corporation)
Nonregulated businesses
SCANA Energy Marketing, Inc. (Energy Marketing)
SCANA Communications, Inc. (SCI)
SCANA Propane Gas, Inc.
SCANA Propane Storage, Inc.
ServiceCare, Inc.
Primesouth, Inc.
SCANA Resources, Inc.
SCANA Petroleum Resources, Inc. (Petroleum Resources) (in liquidation)
SCANA Development Corporation (in liquidation)
Certain investments are reported using the cost or equity method of
accounting, as appropriate. Significant intercompany balances and transactions
have been eliminated in consolidation except as permitted by Statement of
Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of
Certain Types of Regulation" which provides that profits on intercompany sales
to regulated affiliates are not eliminated if the sales price is reasonable and
the future recovery of the sales price through the rate-making process is
probable.
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of SFAS 71. The accounting
standard requires cost-based rate-regulated utilities to recognize in their
financial statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result the Company has recorded,
as of December 31, 1998, approximately $216 million and $71 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $130 million and $56
million, respectively. The electric and gas regulatory assets of approximately
$50 million and $33 million, respectively (excluding deferred income tax assets)
are being recovered through rates and, as discussed in Note 2B, the Public
Service Commission of South Carolina (PSC) has approved accelerated recovery of
approximately $14 million of the electric regulatory assets. In the future, as a
result of deregulation or other changes in the regulatory environment, the
Company may no longer meet the criteria for continued application of SFAS 71 and
could be required to write off its regulatory assets and liabilities. Such an
event could have a material adverse effect on the Company's results of
operations in the period that a write-off would be required, but it is not
expected that cash flows or financial position would be materially affected.
C. 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 PSC.
D. Utility Plant
Utility plant is stated substantially at original cost. The costs of
additions, renewals and betterments to utility plant, including direct labor,
material and indirect charges for engineering, supervision and an allowance for
funds used during construction, are added to utility plant accounts. The
original cost of utility property retired or otherwise disposed of is removed
from utility plant accounts and generally charged, along with the cost of
removal, less salvage, to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.
SCE&G, operator of the V. C. Summer Nuclear Station (Summer Station),
and Santee Cooper (formerly the South Carolina Public Service Authority) are
joint owners of Summer Station in the proportions of two-thirds and one-third,
respectively. The parties share the operating costs and energy output of the
plant in these proportions. Each party, however, provides its own financing.
Plant-in-service related to SCE&G's portion of Summer Station was approximately
$983.3 million and $978.2 million as of December 31, 1998 and 1997,
respectively. Accumulated depreciation associated with SCE&G's share of Summer
Station was approximately $369.2 million and $323.6 million as of December 31,
1998 and 1997, respectively. SCE&G's share of the direct expenses associated
with operating Summer Station is included in "Other operation" and "Maintenance"
expenses.
E. Allowance for Funds Used During Construction
AFC, a noncash item, reflects the period cost of capital devoted to
plant under construction. This accounting practice results in the inclusion of,
as a component of construction cost, the costs of debt and equity capital
dedicated to construction investment. AFC is included in rate base investment
and depreciated as a component of plant cost in establishing rates for utility
services. The Company's regulated subsidiaries calculated AFC using composite
rates of 8.7%, 9.1% and 9.1% for 1998, 1997 and 1996, 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 incurred.
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 annual 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 annual fuel cost hearing. SCE&G had undercollected through the
electric fuel cost component approximately $3.1 million and $1.3 million at
December 31, 1998 and December 31, 1997, respectively, which are included in
"Deferred Debits - Other."
Customers subject to the gas cost adjustment clause are billed based on
a fixed cost of gas determined by the PSC during annual gas cost recovery
hearings. Any difference between actual gas costs and that contained in rates is
deferred and included when establishing gas costs during the next annual gas
cost recovery hearing. At December 31, 1998 and 1997 the Company had
undercollected through the gas cost recovery procedure approximately $5.2
million and $7.6 million, respectively, which are included in "Deferred Debits
Other."
SCE&G's gas rate schedules for residential, small commercial and small
industrial customers include a weather normalization adjustment, which minimizes
fluctuations in gas revenues due to abnormal weather conditions.
G. Depreciation and Amortization
Provisions for depreciation are recorded using the straight-line method
for financial reporting purposes and are based on the estimated service lives of
the various classes of property.
The composite weighted average depreciation rates were as follows:
1998 1997 1996
- ----------------------------------------------------------------------------
SCE&G 3.02% 3.09% 3.13%
GENCO 2.65% 2.63% 2.68%
Pipeline Corporation 2.63% 2.62% 2.56%
Aggregate of Above 2.98% 3.05% 3.08%
- -----------------------------------------------------------------------------
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 Department
of Energy (DOE) 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.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently scheduled to commence when
the operating license expires in the year 2022. Based on a 1991 study, the
expenditures (on a before-tax basis) related to SCE&G's share of decommissioning
activities were estimated to be approximately $200 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 in each of
1998 and 1997) are used to pay premiums on insurance policies on the lives of
certain Company personnel. SCE&G is the beneficiary of these policies. Through
these insurance contracts, SCE&G is able to take advantage of income tax
benefits and accrue earnings on the fund on a tax-deferred basis. 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. The trust's sources of decommissioning funds under the COMReP
program include investment components of life insurance policy proceeds, return
on investment and the cash transfers from SCE&G described above. SCE&G records
its liability for decommissioning costs in deferred credits.
Pursuant to the National Energy Policy Act passed by Congress in 1992 and
the requirements of the DOE, SCE&G has recorded a liability for its estimated
share of the DOE's decontamination and decommissioning obligation. The
liability, approximately $3.6 million at December 31, 1998, has been included in
"Long-Term Debt, Net." SCE&G is recovering the cost associated with this
liability through the fuel cost component of its rates; accordingly, this amount
has been deferred and is included in "Deferred Debits - Other."
I. Income Taxes
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.
J. Pension Expense
The Company has a noncontributory defined benefit pension plan, which
covers 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
the plan to the extent permitted by the applicable Federal income tax
regulations as determined by an independent actuary.
In addition to pension benefits, the Company provides certain health care
and life insurance benefits to active and retired employees. Retirees share in a
portion of their medical care cost. The Company provides life insurance benefits
to retirees at no charge. 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. Additionally, to accelerate the
amortization of the remaining transition obligation for postretirement benefits
other than pensions, as authorized by the PSC, the Company amortized
approximately $15.7 million, $15.6 million and $6.2 million for the years ended
December 31, 1998, 1997 and 1996, respectively. (See Note 2B.)
Disclosure required for these plans under Statement of Financial Accounting
Standards No. 132, "Employer's Disclosures about Pensions and Other
Postretirement Benefits" are set forth in the following tables:
Components of Net Periodic Benefit Cost
Other
Retirement Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
(Millions of Dollars) (Millions of Dollars)
Service Cost $ 8.3 $ 6.8 $ 6.5 $ 2.6 $ 2.5 $ 2.6
Interest Cost 25.9 23.5 22.0 9.4 7.8 7.8
Expected return on assets (59.3) (41.6) (35.5) N/A N/A N/A
Prior service cost amortization 1.1 1.1 1.4 0.7 0.7 0.7
Actuarial (gain) loss (9.6) (7.0) (5.2) 1.0 0.1 0.5
Transition amount amortization 0.8 0.8 0.8 19.1 18.9 9.5
------ ------ ------ ----- ----- -----
Net periodic benefit (income)/cost $(32.8) $(16.4) $(10.0) $32.8 $30.0 $21.1
====== ====== ====== ===== ===== =====
Weighted-Average Assumptions as of December 31
Other
Retirement Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
Discount rate 7.0% 7.5% 7.5% 7.0% 7.5% 7.5%
Expected return on plan assets 9.5% 8.0% 8.0% NA NA NA
Rate of compensation increase 4.0% 4.0% 3.0% 4.0% 4.0% 3.0%
Change in Benefit Obligation
Other
Retirement Benefits Postretirement Benefits
1998 1997 1998 1997
(Millions of Dollars) (Millions of Dollars)
Benefit obligation, January 1 $344.3 $306.9 $108.8 $110.1
Service cost 8.3 6.8 2.6 2.5
Interest cost 25.9 23.5 9.4 7.8
Plan participants' contributions 0.2 0.2 0.5 0.5
Actuarial (gain)/loss 28.3 25.1 23.3 (5.2)
Benefits paid (17.7) (18.1) (7.6) (6.9)
------ ----- ------ ------
Benefit obligation, December 31 $389.3 $344.4 $137.0 $108.8
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
1998 1997
(Millions of Dollars)
Fair value of plan assets, January 1 $632.9 $523.5
Actual return on plan assets 83.5 119.5
Company contribution - 7.8
Plan participants' contributions 0.2 0.2
Benefits paid (17.7) (18.1)
------ ------
Fair value of plan assets, December 31 $698.8 $632.9
====== ======
The Company does not fund postretirement benefits other than pensions.
Funded Status of Plans
Other
Retirement Benefits Postretirement Benefits
1998 1997 1998 1997
Millions of Dollars) (Millions of Dollars)
Funded status, December 31 $309.5 $288.5 $(137.0) $(108.8)
Unrecognized actuarial (gain)/loss (213.4) (227.1) 34.5 12.2
Unrecognized prior service cost 12.3 13.4 5.1 5.8
Unrecognized net transition
obligation 6.5 7.4 10.7 29.8
------ ------ ------- -------
Net amount recognized in
Consolidated Balance Sheets $114.9 $ 82.2 $ (86.7) $ (61.0)
====== ====== ======= =======
Health Care Trends
The determination of net periodic postretirement benefit cost is based on the
following assumptions:
1998 1997 1996
- --------------------------------------------------------------------------------
Health care cost trend rate 8.5% 9.0% 9.5%
Ultimate health care cost trend rate 5.0% 5.5% 5.5%
Year achieved 2005 2004 2004
The effect of a one-percentage-point increase or decrease in the assumed health
care cost trend rates on the aggregate of the service and interest cost
components of net periodic postretirement health care benefit cost and the
accumulated postretirement benefit obligation for health care benefits are as
follows:
1% 1%
Increase Decrease
(Millions of Dollars)
Effect on health care cost $0.2 $(0.3)
Effect on postretirement obligation 3.5 (3.9)
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
For regulatory purposes, 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, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations. Such amounts are deferred and
amortized with recovery provided through rates. The Company has also recovered
portions of its environmental liabilities through settlements with various
insurance carriers. As of December 31, 1998, the Company has recovered all
amounts previously deferred for its electric operations. The Company expects to
recover all deferred amounts related to its gas operations by December 2002.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $21.3 million and $32.4 million at December 31, 1998 and
1997, respectively. The deferral includes the estimated costs associated with
the matters discussed in Note 10C.
M. Oil and Gas
On December 1, 1997 substantially all of the assets of the Company's oil
and gas exploration and production subsidiary, Petroleum Resources, were sold
for $110 million, resulting in an after-tax gain of $17.6 million. The Company
followed the full cost method of accounting for its oil and gas operations and,
accordingly, capitalized all costs it incurred in the acquisition, exploration
and development of interests in oil and gas properties. In addition, the
capitalized costs were subject to a ceiling test. However, no non-cash
writedowns resulted from the application of the ceiling test for the years ended
December 31, 1997 or 1996.
N. Temporary Cash Investments
The Company considers temporary cash investments having original
maturities of three months or less to be cash equivalents. Temporary cash
investments are generally in the form of commercial paper, certificates of
deposit and repurchase agreements.
O. Recently Issued Accounting Standard
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The provisions of the Statement, which will be implemented by the
Company for the fiscal year beginning January 1, 2000, establish accounting and
reporting standards for derivative instruments, including those imbedded in
other contracts, and hedging activities. The impact that adoption of the
provisions of the Statement will have on the Company's results of operations,
cash flows and financial position has not been determined.
P. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the 1998 presentation.
Q. Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
2. RATE MATTERS
A. On December 11, 1998, the PSC issued an order requiring SCE&G to
reduce retail electric rates on a prospective basis. The PSC acted in response
to SCE&G reporting that it earned a 13.04 percent return on common equity for
its retail electric operations for the twelve months ended September 30, 1998.
This return on common equity exceeded SCE&G's authorized return of 12.0 percent
by 1.04 percent, or $22.7 million, primarily as a result of record heat
experienced during the summer. The order requires prospective rate reductions on
a per kilowatt-hour basis, based on actual retail sales for the twelve months
ended September 30, 1998. This action will reduce future reported return on
common equity to the Commission-authorized level if SCE&G experiences the same
weather effect and other business results as that of the twelve months ended
September 30, 1998. The order requires the rate reductions to be placed into
effect with the first billing cycle of January 1999. On December 21, 1998, SCE&G
filed a motion for reconsideration with the PSC. On January 12, 1999, the PSC
denied SCE&G's motion for reconsideration, ruled that no further rate action was
required, and reaffirmed SCE&G's return on equity of 12.0 percent.
B. On January 9, 1996 the PSC issued an order granting SCE&G an increase
in retail electric rates of 7.34%, which was designed to produce additional
revenues, based on a test year, of approximately $67.5 million annually. The
increase was implemented in two phases. The first phase, an increase in revenues
of approximately $59.5 million annually or 6.47%, commenced in January 1996. The
second phase, an increase in revenues of approximately $8.0 million annually, or
.87%, was implemented in January 1997. The PSC authorized a return on common
equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over a ten-year
period. Additionally, the PSC approved accelerated recovery of a significant
portion of SCE&G's electric regulatory assets (excluding deferred income tax
assets) and the remaining transition obligation for postretirement benefits
other than pensions, changing the amortization periods to allow recovery by the
end of the year 2000. SCE&G's request to shift, for ratemaking purposes,
approximately $257 million of depreciation reserves from transmission and
distribution assets to nuclear production assets was also approved. The Consumer
Advocate and two other intervenors appealed certain issues in the order
initially to the Circuit Court, which affirmed the PSC's decisions, and,
subsequently, to the Supreme Court. In March 1998, SCE&G, the PSC, the Consumer
Advocate and one of the other intervenors reached an agreement that provided for
the reversal of the shift in depreciation reserves and the dismissal of the
appeal of all other issues. The PSC also authorized SCE&G to adjust depreciation
rates that had been approved in the 1996 rate order for its electric
transmission, distribution and nuclear production properties to eliminate the
effect of the depreciation reserve shift and to retroactively apply such
depreciation rates to February 1996. As a result, a one-time reduction in
depreciation expense of $5.5 million after taxes was recorded in March 1998. The
agreement does not affect retail electric rates. The FERC had previously
rejected the transfer of depreciation reserves for rates subject to its
jurisdiction. In September 1998, the Supreme Court affirmed the Circuit Court's
rulings on the issues contested by the remaining intervenor.
C. In 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 is
subject to annual review and provides for the recovery of substantially all
actual and projected site assessment and cleanup costs and environmental claims
settlements for SCE&G's gas operations that had previously been deferred. In
October 1998, as a result of the annual review, the PSC approved SCE&G's request
to maintain the billing surcharge at $.011 per therm which should enable SCE&G
to recover the remaining balance of $22.1 million by December 2002.
D. In September 1992 the PSC issued an order granting SCE&G a $.25
increase in transit fares from $.50 to $.75 in Columbia, 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 in October 1992. SCE&G appealed the PSC's order to
the Circuit Court, which in May 1995 ordered the case back to the PSC for
reconsideration of several issues including the low income rider program,
routing changes, and the $.75 fare. The Supreme Court declined to review an
appeal of the Circuit Court decision and dismissed the case. The PSC and other
intervenors filed another Petition for Reconsideration, which the Supreme Court
denied. The PSC and other intervenors filed another appeal to the Circuit Court
which the Circuit Court denied in an order dated May 9, 1996. In this order, the
Circuit Court upheld its previous orders and remanded them to the PSC. During
August 1996, the PSC heard oral arguments on the orders on remand from the
Circuit Court. On September 30, 1996, the PSC issued an order affirming its
previous orders and denied SCE&G's request for reconsideration. SCE&G has
appealed these two PSC orders to the Circuit Court where they are awaiting
action.
E. On August 8, 1990, the PSC issued an order 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
appealed 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 Circuit Court decision and reinstated the
PSC order. 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. The PSC then held another
hearing and issued its order dated December 12, 1995 maintaining the present
level of the maximum markup on industrial sales ("cap"). This Order was appealed
to the Circuit Court by Pipeline Corporation and the industrial customer group
with several other parties intervening, including the Consumer Advocate of South
Carolina. On October 10, 1997, the Circuit Court issued an order in favor of the
Consumer Advocate and the industrial customer group and remanded the case to the
PSC to determine an overall rate of return for Pipeline Corporation. The Circuit
Court also issued a second order which ruled against Pipeline Corporation and
affirmed the PSC's decision that the cap should not be increased. Several
motions and appeals were filed subsequently at the Supreme Court. The Supreme
Court has dismissed the appeals of the PSC and Pipeline Corporation from the
first order without prejudice until the PSC completes proceedings on remand and
has held Pipeline Corporation's appeal of the second order in abeyance until the
PSC completes proceedings on remand. The remanded case was heard by the PSC in
June 1998. The PSC set an overall rate of return on equity for Pipeline
Corporation of 12.5-16.5%. The South Carolina Energy Users Committee (SCEUC)
appealed the order to the Circuit Court. Pipeline Corporation subsequently filed
a Motion to Dismiss the SCEUC's appeal on the grounds that it was not timely
filed. These cases should be heard in 1999.
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including the amounts
due under the nuclear and fossil fuel agreements (see Note 4), and sinking fund
requirements for the years 1999 through 2003 are summarized as follows:
Year Amount Year Amount
(Millions of Dollars)
1999 $106.5 2002 $ 27.5
2000 213.5 2003 284.4
2001 27.5
Approximately $18.5 million of the portion of long-term debt payable in
1999 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.
On January 13, 1998 the Company issued $60 million of medium-term notes
due January 13, 2003 at an interest rate of 6.05%. Proceeds from the notes were
used to repay unsecured bank loans totaling $60 million due January 9, 1998
which were classified as long-term debt at December 31, 1997.
On August 7, 1996 the City of Charleston executed 30-year electric and
gas franchise agreements with SCE&G. In consideration for the electric franchise
agreement, SCE&G is paying the City $25 million over seven years (1996-2002) and
has donated to the City the existing transit assets in Charleston. The $25
million is included in electric plant-in-service. In settlement of environmental
claims the City may have had against SCE&G involving the Calhoun Park area,
where SCE&G and its predecessor companies operated a manufactured gas plant
until the 1960's, SCE&G is paying the City $26 million over a four-year period
(1996-1999). Such amount is deferred (see Note 1L). The unpaid balances of these
amounts are included in "Long-Term Debt."
SCE&G has three-year revolving lines of credit totaling $75 million, in
addition to other lines of credit, that provide liquidity for issuance of
commercial paper. The three-year lines of credit provide back-up liquidity when
commercial paper outstanding is in excess of $175 million. The long-term nature
of the lines of credit allow commercial paper in excess of $175 million to be
classified as long-term debt. SCE&G's commercial paper outstanding totaled $
125.2 million and $13.3 million at December 31, 1998 and 1997 at weighted
average interest rates of 5.32% and 5.90%, respectively.
Substantially all utility plant and fuel inventories are pledged as collateral
in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories and sulfur dioxide emission
allowances are financed by Fuel Company through the issuance of short-term
commercial paper. These short-term borrowings are supported by an irrevocable
revolving credit agreement which expires December 19, 2000. Accordingly, the
amounts outstanding have been included in long-term debt. The credit agreement
provides for a maximum amount of $125 million that may be outstanding at any
time.
Commercial paper outstanding totaled $66.0 million and $80.3 million at
December 31, 1998 and 1997 at weighted average interest rates of 5.45% and
5.87%, respectively.
5. COMMON EQUITY:
The changes in "Common Stock," without par value, during 1998, 1997 and
1996 are summarized as follows:
Number Millions
of Shares of Dollars
Balance December 31, 1995 103,623,863 $1,056.7
Issuance of common stock 2,551,410 68.6
- ----------------------------------------------------------------------------
Balance December 31, 1996 106,175,273 1,125.3
Issuance of common stock 1,145,840 27.6
- ---------------------------------------------------------------------------
Balance December 31, 1997 107,321,113 1,152.9
Repurchase of common stock (3,748,490) (110.0)
- ---------------------------------------------------------------------------
Balance December 31, 1998 103,572,623 $1,042.9
============================================================================
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, under certain circumstances,
could limit the payment of cash dividends on its common stock. In addition, with
respect to hydroelectric projects, the Federal Power Act requires the
appropriation of a portion of certain earnings therefrom. At December 31, 1998
approximately $25.1 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.
Cash dividends on common stock were declared at an annual rate per share of
$1.54, $1.51 and $1.47 for 1998, 1997 and 1996, respectively.
6. PREFERRED STOCK:
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend. Retirements under sinking fund
requirements are at par values.
The aggregate annual amount of purchase fund or sinking fund requirements
for preferred stock for the years 1999 through 2003 is $2.8 million.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 1998, 1997 and 1996 are summarized as follows:
Number Millions
of Shares of Dollars
Balance December 31, 1995 763,619 $ 48.7
Shares Redeemed:
$100 par value (7,198) (0.7)
$50 par value (50,319) (2.6)
- -------------------------------------------------------------------------
Balance December 31, 1996 706,102 45.4
Shares Redeemed:
$100 par value (202,812) (20.3)
$50 par value (252,196) (12.6)
- -------------------------------------------------------------------------
Balance December 31, 1997 251,094 12.5
Shares Redeemed:
$50 par value (11,042) (1.0)
-----------------------------------------------------------------------
Balance December 31, 1998 240,052 $ 11.5
=========================================================================
On October 28, 1997, SCE&G Trust I (the "Trust"), a wholly-owned
subsidiary of SCE&G, issued $50 million (2,000,000 shares) of 7.55% Trust
Preferred Securities, Series A (the "Preferred Securities"). SCE&G owns all of
the Common Securities of the Trust (the "Common Securities"). The Preferred
Securities and the Common Securities (the "Trust Securities") represent
undivided beneficial ownership interests in the assets of the Trust. The Trust
exists for the sole purpose of issuing the Trust Securities and using the
proceeds thereof to purchase from SCE&G its 7.55% Junior Subordinated Debentures
due September 30, 2027. The sole asset of the Trust is $50 million of Junior
Subordinated Debentures of SCE&G. Accordingly, no financial statements of the
Trust are presented. SCE&G's obligations under the Guarantee Agreement entered
into in connection with the Preferred Securities, when taken together with
SCE&G's obligation to make interest and other payments on the Junior
Subordinated Debentures issued to the Trust and SCE&G's obligations under the
Indenture pursuant to which the Junior Subordinated Debentures were issued,
provides a full and unconditional guarantee by SCE&G of the Trust's obligations
under the Preferred Securities. Proceeds were used to redeem preferred stock of
SCE&G.
The preferred securities of SCE&G Trust I are redeemable only in
conjunction with the redemption of the related 7.55% Junior Subordinated
Debentures. The Junior Subordinated Debentures will mature on September 30, 2027
and may be redeemed, in whole or in part, at any time on or after September 30,
2002 or upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is
received from counsel experienced in such matters that there is more than an
insubstantial risk that: (1) the Trust is or will be subject to Federal income
tax, with respect to income received or accrued on the Junior Subordinated
Debentures, (2) interest payable by SCE&G on the Junior Subordinated Debentures
will not be deductible, in whole or in part, by SCE&G for Federal income tax
purposes, or (3) the Trust will be subject to more than a de minimis amount of
other taxes, duties, or other governmental charges.
Upon the redemption of the Junior Subordinated Debentures, payment will
simultaneously be applied to redeem Preferred Securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Subordinated Debentures. The Preferred Securities are redeemable at $25 per
preferred security plus accrued dividends.
7. INCOME TAXES:
Total income tax expense for 1998, 1997 and 1996 is as follows:
1998 1997 1996
- --------------------------------------------------------------------------
(Millions of Dollars)
Current taxes:
Federal $114.8 $101.3 $ 98.3
State 2.2 (5.4) 14.1
- ----------------------------------------------------------------------------
Total current taxes 117.0 95.9 112.4
- ----------------------------------------------------------------------------
Deferred taxes, net:
Federal 2.3 3.5 8.6
State 2.0 0.3 1.7
- ----------------------------------------------------------------------------
Total deferred taxes 4.3 3.8 10.3
- ----------------------------------------------------------------------------
Investment tax credits:
Deferred - State 14.3 19.0 -
Amortization of amounts
deferred - State (0.9) (1.5) -
Amortization of amounts
deferred - Federal (3.6) (3.6) (3.6)
- ----------------------------------------------------------------------------
Total investment tax credits 9.8 13.9 (3.6)
- ----------------------------------------------------------------------------
Total income tax expense $131.1 $113.6 $119.1
============================================================================
The difference in total income tax expense and the amount calculated from
the application of the statutory Federal income tax rate (35% for 1998, 1997 and
1996) to pre-tax income is reconciled as follows:
1998 1997 1996
- ----------------------------------------------------------------------------
(Millions of Dollars)
Net income $223.4 $220.7 $215.3
Total income tax expense:
Charged to operating expenses 136.2 105.4 118.0
Charged (credited) to other items (5.1) 8.2 1.1
Preferred stock dividends 7.5 9.2 5.4
- ----------------------------------------------------------------------------
Total pre-tax income $362.0 $343.5 $339.8
============================================================================
Income taxes
on above at statutory
Federal income tax rate $126.7 $120.2 $118.9
Increases (decreases) attributable to:
State income taxes
(less Federal income tax effect) 11.4 8.1 10.2
Deferred income tax reversal at higher
than statutory rates (3.6) (4.2) (4.1)
Amortization of Federal investment
tax credits (3.6) (3.6) (3.6)
Allowance for equity funds used
during construction (2.8) (2.5) (2.5)
Other differences, net 3.0 (4.4) 0.2
- ----------------------------------------------------------------------------
Total income tax expense $131.1 $113.6 $119.1
============================================================================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability at December 31, 1998 and 1997 are as
follows:
1998 1997
- ------------------------------------------------------------------------------
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 66.9 $ 60.7
Cycle billing 20.6 20.5
Early retirement programs 13.0 2.7
Deferred compensation 7.4 6.9
Other postretirement benefits 32.9 14.6
Other 23.7 11.6
- ------------------------------------------------------------------------------
Total deferred tax assets 164.5 117.0
- ------------------------------------------------------------------------------
Deferred tax liabilities:
Property, plant and equipment 658.8 634.3
Pension expense 39.2 27.5
Research and experimentation 32.5 19.5
Reacquired debt 7.5 7.5
Investments in equity securities 20.5 5.3
Other 12.2 10.4
- ------------------------------------------------------------------------------
Total deferred tax liabilities 770.7 704.5
- ------------------------------------------------------------------------------
Net deferred tax liability $606.2 $587.5
==============================================================================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of the Company through 1989, and has examined and proposed
adjustments to the Company's Federal returns for 1990 through 1995. The Company
does not anticipate that any adjustments which might result from these
examinations will have a significant impact on the results of operations, cash
flows or financial position of the Company.
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1998 and 1997 are as follows:
1998 1997
- ------------------------------------------------------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Millions of Dollars)
Assets:
Cash and temporary
cash investments $ 62.0 $ 62.0 $ 59.7 $ 59.7
Investments 409.7 464.7 290.5 341.9
Liabilities:
Short-term borrowings 194.6 194.6 58.7 58.7
Long-term debt 1,729.7 1,869.2 1,639.5 1,722.4
Preferred stock
(subject to purchase
or sinking funds) 11.5 11.3 12.5 11.3
- -----------------------------------------------------------------------------
The information presented herein is based on pertinent information
available to the Company as of December 31, 1998 and 1997. 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, 1998, 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:
o Cash and temporary cash investments, including commercial paper,
repurchase agreements, treasury bills and notes, are valued at
their carrying amount.
o Fair values of investments and long-term debt are based on quoted
market prices of the instruments or similar instruments, or for
those instruments for which there are no quoted market prices
available, fair values are based on net present value
calculations. Investments which are not considered to be
financial instruments 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.
o Short-term borrowings are valued at their carrying amount.
o The fair value of preferred stock (subject to purchase or sinking
funds) is estimated on the basis of market prices.
o Potential taxes and other expenses that would be incurred in an
actual sale or settlement have not been taken into consideration.
At December 31, 1998, SCI held the following investments in ITC Holding
Company (ITC) and its affiliates:
o Powertel, Inc. (Powertel) is a publicly traded company that owns and
operates personal communications services (PCS) systems in several major
Southeastern markets. SCI owns approximately 4.6 million common shares of
Powertel. SCI's investment in Powertel's common shares of approximately
$68.0 million had a market value of $62.5 million at December 31, 1998,
resulting in a pre-tax unrealized holding loss of $5.5 million. The
after-tax amount of such loss is included in the balance sheet as a
component of "Common Equity." In addition, SCI owns the following series of
non-voting convertible preferred shares, at the approximate cost noted:
100,000 shares series B ($75.1 million), 50,000 shares series D ($22.5
million) and 50,000 shares 6.5% series E ($75.0 million). Preferred series
B shares are convertible in March 2002 at a conversion price of $16.50 per
common share or approximately 4.5 million common shares. Preferred series D
shares are convertible in March 2002 at a conversion price of $12.75 per
common share or approximately 1.7 million common shares. Preferred series E
shares purchased in June 1998 are convertible in June 2003 at a conversion
price of $22.01 per common share or approximately 3.4 million common
shares. The market value of the convertible preferred shares of Powertel is
not readily determinable. However, on an as converted basis, the market
value of the underlying common shares for the preferred shares was
approximately $131.8 million at December 31, 1998, resulting in an
unrecorded pre-tax holding loss of $40.8 million.
o ITC Delta^Com, Inc. (ITCD) is a fiber optic telecommunications provider.
SCI owns approximately 4.1 million common shares of ITCD. SCI's investment
in ITCD's common shares of approximately $16.2 million had a market value
of $61.8 million at December 31, 1998, resulting in a pre-tax unrealized
holding gain of $45.6 million. The after-tax amount of such gain is
included in the balance sheet as a component of "Common Equity." In
addition, SCI owns 1,480,771 shares of series A preferred stock of ITCD at
a cost of approximately $11.2 million. Series A preferred shares are
convertible in March 2002 into 2,961,542 shares of ITCD common stock (after
giving effect to the two-for-one stock split). The market value of series A
preferred stock of ITCD is not readily determinable. However, on an as
converted basis the market value of the underlying common stock for the
series A preferred stock was approximately $45.2 million at December 31,
1998, resulting in an unrecorded pre-tax holding gain of $33.9 million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of cable,
television, telephone and internet services. SCI owns 71,050 units of
Knology. Each unit consists of one 11.875% Senior Discount Note due 2007
and one warrant entitling the holder to purchase .003734 shares of
preferred stock of Knology. The cost of this investment was approximately
$40 million. SCI also owns an additional 753 warrants which entitles it to
purchase 753 shares of preferred stock at $1,500 per share. Effective July
31, 1998, SCI sold all of its 3,639 shares of preferred stock in Knology to
ITC. For each preferred share sold, SCI received $1,600 of ITC series B
convertible preferred shares, for a total of 133,664 shares. SCI also
received approximately $0.4 million in cash. SCI's original investment in
these shares was approximately $5.3 million.
o ITC has an ownership interest in several Southeastern communications
companies. SCI owned approximately 3.1 million common shares (after giving
effect to a four-for-one stock split on August 25, 1998), 645,153 series A
convertible preferred shares, and 133,664 series B convertible preferred
shares of ITC. These investments cost approximately $7.1 million, $8.9
million, and $5.0 million, respectively. Series A and series B preferred
shares are convertible in March 2002 into ITC common shares at a conversion
price of $13.45 and $43.56, respectively, on a four to one basis. The
market value of these investments is not readily determinable.
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its committed lines of
credit. Commercial paper borrowings are for 270 days or less. Details of lines
of credit (including uncommitted lines of credit) and short-term borrowings,
excluding amounts classified as long-term (Notes 3 and 4), at December 31, 1998
and 1997 and for the years then ended are as follows:
1998 1997
(Millions of Dollars)
Authorized lines of credit at year-end $513.0 $564.0
Unused lines of credit at year-end $443.8 $518.8
Short-term borrowings outstanding at year-end:
Bank loans $69.4 $45.4
Weighted average interest rate 6.66% 6.44%
Commercial paper $125.2 $13.3
Weighted average interest rate 5.32% 5.90%
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10. COMMITMENTS AND CONTINGENCIES:
A. Construction
The Company and Westvaco each own a 50% interest in Cogen South LLC
(Cogen). Cogen was formed to build and operate a cogeneration facility at
Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina.
Construction of the facility began in September 1996 and is in the final stages.
Construction financing of approximately $170 million was provided to Cogen by
banks. On September 10, 1998, the contractor in charge of construction filed
suit in Circuit Court seeking approximately $51 million from Cogen, alleging
that construction cost overruns relating to the facility were incurred and that
the construction contract provides for recovery of these costs. In addition to
Cogen, Westvaco, SCE&G and the Company are also named in the suit. The Company
and the other defendants believe the suit is without merit and are mounting an
appropriate defense. The Company does not believe that the resolution of this
issue will have a material impact on its results of operations, cash flows or
financial position.
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 $9.7 billion. Each
reactor licensee is currently liable for up to $88.1 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 $58.7 million per incident, but not
more than $6.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric Insurance Limited (NEIL) and American Nuclear
Insurers (ANI) providing combined property and decontamination insurance
coverage of $2.0 billion for any losses at Summer Station. SCE&G pays annual
premiums and, in addition, could be assessed a retroactive premium not to exceed
five times its annual premium in the event of property damage loss to any
nuclear generating facility covered under the NEIL program. Based on the current
annual premium, this retroactive premium assessment would not exceed $6.1
million.
To the extent that insurable claims for property damage, decontamination,
repair and replacement and other costs and expenses arising from a nuclear
incident at Summer Station exceed the policy limits of insurance, or to the
extent such insurance becomes unavailable in the future, and to the extent that
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 material adverse impact on the Company's results
of operations, cash flows and financial position.
C. Environmental
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 encompasses approximately 30 acres
and includes properties which were locations for industrial operations,
including a wood preserving (creosote) plant, one of SCE&G's decommissioned
manufactured gas plants, properties owned by the National Park Service and the
City of Charleston, and private properties. The site has not been placed on the
National Priorities List, but may be added in the future. The Potentially
Responsible Parties (PRPs) have negotiated an administrative order by consent
for the conduct of a Remedial Investigation/Feasibility Study and a
corresponding Scope of Work. Field work began in November 1993, and the EPA
approved a Remedial Investigation Report in February 1997 and a Feasibility
Study Report in June 1998. In July 1998, the EPA approved SCE&G's Removal Action
Work Plan for soil excavation. SCE&G completed Phase One of the Removal Action
in 1998 at a cost of approximately $1.5 million. Phase Two will include
excavation and installation of several permanent barriers to mitigate coal tar
seepage. Phase Two began in November 1998, and is expected to cost approximately
$2.2 million. On September 30, 1998 a Record of Decision, was issued which sets
forth EPA's view of the extent of each PRP's responsibility for site
contamination and the level to which the site must be remediated. On January 13,
1999 the EPA issued a Unilateral Administrative Order for Remedial Design and
Remedial Action directing SCE&G to design and carry out a plan of remediation
for the Calhoun Park site. The Order is temporarily stayed pending further
negotiations between SCE&G and the EPA.
In October 1996 the City of Charleston and SCE&G settled all
environmental claims the City may have had against SCE&G involving the Calhoun
Park area for a payment of $26 million over four years (1996-1999) by SCE&G to
the City. SCE&G is recovering the amount of the settlement, which does not
encompass site assessment and cleanup costs, through rates in the same manner as
other amounts accrued for site assessments and cleanup as discussed above. As
part of the environmental settlement, SCE&G has agreed to construct an 1,100
space parking garage on the Calhoun Park site and to transfer the facility to
the City in exchange for a 20-year municipal bond backed by revenues from the
parking garage and a mortgage on the parking garage. The total amount of the
bond is not to exceed $16.9 million, the maximum expected project cost. The
parking garage is currently under construction and is scheduled for completion
in the spring of the year 2000.
SCE&G owns three other decommissioned manufactured gas plant sites which
contain residues of by-product chemicals. For the site located in Sumter, South
Carolina, effective September 15, 1998, SCE&G entered into a Remedial Action
Plan Contract with the South Carolina Department of Health and Environmental
Control (DHEC) pursuant to which it agreed to undertake a full site
investigation and remediation under the oversight of DHEC. Site investigation
and characterization are proceeding according to schedule. Upon selection and
successful implementation of a site remedy, DHEC will give SCE&G a Certificate
of Completion, and a covenant not to sue. SCE&G is continuing to investigate the
other two sites, and is monitoring the nature and extent of residual
contamination.
D. Franchise Agreement
See Note 3 for a discussion of the electric franchise agreement between
SCE&G and the City of Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation incidental to its
business operations which management anticipates will be resolved without
material loss to the Company. No estimate of the range of loss from these
matters can currently be determined.
11. SEGMENT OF BUSINESS INFORMATION:
The Company's reportable segments, based on combined revenues from
external and internal sources, are Electric Operations, Gas Distribution, Gas
Transmission and Energy Marketing. Electric Operations is comprised of the
electric portion of SCE&G, GENCO and Fuel Company. This segment is primarily
engaged in the generation, transmission and distribution of electricity. SCE&G's
electric service territory extends into 24 counties covering more than 15,000
square miles in the central, southern and southwestern portions of South
Carolina. Sales of electricity to industrial, commercial and residential
customers are regulated by the PSC. SCE&G is also regulated by the FERC. GENCO
owns and operates the Williams Station generating facility and sells all of its
electric generation to SCE&G. GENCO is regulated by the FERC. Fuel Company
acquires, owns and provides financing for the fuel and emission allowances
required for the operation of SCE&G's generation facilities.
Gas Distribution is comprised of SCE&G's local distribution operations.
This segment is engaged in the purchase and sale, primarily at retail, of
natural gas. These operations extend to 30 counties in South Carolina covering
approximately 21,000 square miles. Gas Transmission is comprised of Pipeline
Corporation, which is engaged in the purchase, transmission and sale of natural
gas on a wholesale basis to distribution companies (including SCE&G), and
directly to industrial customers in 40 counties throughout South Carolina.
Pipeline Corporation also owns LNG liquefaction and storage facilities. Both gas
segments are regulated by the PSC. Energy Marketing is comprised of SCANA
Energy, which markets electricity, natural gas and other light hydrocarbons
primarily in the southeast. SCANA Energy also markets natural gas in Georgia's
deregulated natural gas market.
The accounting policies of the segments are the same as those described
in the summary of significant accounting policies. The Company records regulated
inter-affiliate sales and transfers of electricity and gas based on rates
established by the appropriate regulatory authority. Non-regulated sales and
transfers are recorded at current market prices.
The Company's reportable segments share a similar regulatory environment
and, in some cases, an overlapping service area. However, Electric Operations'
product differs from the other segments, as does its generation process and
method of distribution. The gas segments differ from each other primarily based
on the class of customers each serves and the marketing strategies resulting
from those differences. Energy Marketing is a non-regulated segment.
Disclosure of Reportable Segments
(Millions of Dollars)
Electric Gas Gas Energy All
1998 Operations1 Distribution Transmission Marketing Other2 Total
External Customer Revenue 1,220 226 185 568 69 2,268
Revenue from Affiliates 286 5 145 - 8 444
Operating Income (Loss) 319 21 20 - (5) 355
Interest Expense n/a n/a 4 - 19 23
Depreciation & Amortization 126 12 7 - 11 156
Income Tax n/a n/a 8 (8) (2) (2)
Segment Net Income n/a n/a 16 (14) (4) (2)
Segment Assets 4,600 381 239 73 764 6,057
Expenditures for Assets 205 19 11 4 56 295
Deferred Tax Assets n/a n/a 3 - 9 12
Electric Gas Gas Energy All
1997 Operations1 Distribution Transmission Marketing Other2 Total
External Customer Revenue 1,103 231 188 207 88 1,817
Revenue from Affiliates 124 3 152 2 50 331
Operating Income (Loss) 280 22 21 - (4) 319
Interest Expense n/a n/a 4 - 14 18
Depreciation & Amortization 135 11 6 1 28 181
Income Tax n/a n/a 7 - 9 16
Segment Net Income n/a n/a 18 (1) 19 36
Segment Assets 4,417 364 243 40 614 5,678
Expenditures for Assets 189 15 18 - 70 292
Deferred Tax Assets n/a n/a 5 - (1) 4
Electric Gas Gas Energy All
1996 Operations1 Distribution Transmission Marketing Other2 Total
External Customer Revenue 1,107 232 171 252 71 1,833
Revenue from Affiliates 119 2 156 1 71 349
Operating Income (Loss) 289 19 17 - (6) 319
Interest Expense n/a n/a 2 - 11 13
Depreciation & Amortization 129 12 6 1 38 186
Income Tax n/a n/a 9 (3) 6 12
Segment Net Income n/a n/a 17 (4) 16 29
Segment Assets 4,256 350 231 34 551 5,422
Expenditures for Assets 185 19 30 1 59 294
Deferred Tax Assets n/a n/a 3 - 12 15
Significant non-cash activities 21 20 - - - 41
1Management uses operating income and utility plant to measure segment
profitability and financial position, respectively, for Electric Operations, Gas
Distribution and Transit Operations. Therefore, SCE&G's interest expense,
depreciation and amortization, income taxes, segment net income and deferred tax
assets are not allocated between segments. Management uses net income and total
assets to measure segment profitability and financial position for all other
segments. Interest income is not reported by segment and is not material.
2Revenues and assets from segments below the quantitative thresholds are
attributable to SCE&G's transit operations, which are regulated by the PSC, and
to nine other wholly owned subsidiaries of SCANA. These subsidiaries conduct
non-regulated operations in the electric, natural gas and telecommunications
industries. Revenues are derived primarily from sales of propane, appliance
warranties and home security systems and from fiber optics and radio networks.
None of these subsidiaries met any of the quantitative thresholds for
determining reportable segments in 1998, 1997 or 1996. Significant non-cash
activities included the Charleston electric franchise agreement and the
Charleston environmental agreement related to a manufactured gas plant site.
Reconciliation of Reportable Segments
To Consolidated Financial Statements
(Millions of Dollars)
Total Operating Net
1998 Revenue Income/(Loss) Income Assets
- ---------------------------------------------------------------------------
Reportable Segments $2,635 $360 $ 2 $5,293
All Other 77 (5) (4) 764
Unallocated - (6) 225 (625)
Elimination of Affiliates (444) (4) - (41)
Adjustments (636) - - (110)
- ---------------------------------------------------------------------------
Consolidated Totals $1,632 $345 $223 $5,281
- ---------------------------------------------------------------------------
Total Operating Net
1997 Revenue Income/(Loss) Income Assets
- ---------------------------------------------------------------------------
Reportable Segments $2,010 $323 $ 17 $5,064
All Other 138 (4) 19 614
Unallocated - - 190 (614)
Elimination of Affiliates (331) (5) (5) (49)
Adjustments (294) - - (83)
- ---------------------------------------------------------------------------
Consolidated Totals $1,523 $314 $221 $4,932
- -------------------------------------------------------------------------------
Total Operating Net
1996 Revenue Income/(Loss) Income Assets
- -----------------------------------------------------------------------------
Reportable Segments $2,040 $325 $ 13 $4,871
All Other 142 (6) 16 551
Unallocated - - 190 (529)
Elimination of Affiliates (349) (5) (4) (53)
Adjustments (320) - - (81)
- -----------------------------------------------------------------------------
Consolidated Totals $1,513 $314 $215 $4,759
- -----------------------------------------------------------------------------
The Consolidated Financial Statements report operating revenues,
comprised of the reportable segments, except Energy Marketing, and the
non-reportable transit operations segment. Energy Marketing's revenues and
revenues from other non-reportable segments are included in Other Income.
Therefore, the adjustments to total revenue remove revenues from non-regulated
segments. Adjustments to assets consist of various reclassifications made for
external reporting purposes. Unallocated net income consists of SCE&G's net
income. Segment assets include utility plant only (excluding accumulated
depreciation) for Electric Operations, Gas Distribution and Transit Operations,
and all assets for Gas Transmission and the remaining non-reportable segments.
As a result, unallocated assets include accumulated depreciation, offset in part
by common, non-utility and non-regulated plant for SCANA and SCE&G, and by
non-fixed assets for Electric Operations, Gas Distribution and Transit
Operations.
Reconciliation of Other Significant Items
(Millions of Dollars)
Segment Consolidated
1998 Totals Adjustments Totals
- ------------------------------------------------------------------------------
Interest Charges $ 23 100 123
Depreciation and Amortization 156 (11) 145
Income Tax/(Benefit) (2) 138 136
Expenditures for Assets 295 8 303
Deferred Tax Assets 12 10 22
- -----------------------------------------------------------------------------
Segment Consolidated
1997 Totals Adjustments Totals
- ----------------------------------------------------------------------------
Interest Charges $ 18 103 121
Depreciation and Amortization 181 (28) 153
Income Tax/(Benefit) 16 89 105
Expenditures for Assets 292 (4) 288
Deferred Tax Assets 4 21 25
- ----------------------------------------------------------------------------
Segment Consolidated
1996 Totals Adjustments Totals
- ------------------------------------------------------------------------------
Interest Charges $ 13 109 122
Depreciation and Amortization 186 (38) 148
Income Tax/(Benefit) 12 106 118
Expenditures for Assets 294 (22) 272
Deferred Tax Assets 15 6 21
Significant Non-cash Activities 41 - 41
- ------------------------------------------------------------------------------
Adjustments to Interest Charges, Income Tax/(Benefit) and Deferred Tax
Assets include primarily the totals from SCANA or SCE&G that are not allocated
to the segments. Interest Charges is also adjusted to eliminate inter-affiliate
charges. Adjustments to depreciation and amortization consist of non-regulated
segment expenses, which are not included in the depreciation and amortization
reported on a consolidated basis. Deferred Tax Assets are also adjusted to
remove the non-current portion of those assets. Expenditures for Assets in 1996
are adjusted primarily to remove the non-cash transaction related to the
Charleston Franchise Agreement.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1998
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
(Millions of Dollars, except per share amounts)
Total operating
revenues $406 $387 $474 $365 $1,632
Operating income 91 74 120 60 345
Net income 64 42 86 31 223
Earnings per weighted
average share of
common stock
as reported .60 .40 .82 .30 2.12
- ----------------------------------------------------------------------------
1997
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
(Millions of Dollars, except per share amounts)
Total operating
revenues $385 $332 $418 $388 $1,523
Operating income 81 61 100 72 314
Net income 57 30 75 59 221
Earnings per weighted
average share of
common stock
as reported .54 .28 .69 .55 2.06
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13.
Subsequent Event
On February 17, 1999, the Company and Public Service Company of North
Carolina, Inc. (PSNC) announced a definitive agreement whereby the
Company will acquire PSNC in a transaction valued at approximately $900
million, including the assumption of debt. The transaction will be
accounted for as a purchase. It is anticipated that PSNC will be
operated as a wholly-owned subsidiary of the Company. Completion of the
transaction is subject to the approval of the shareholders of both
companies and applicable regulatory approvals. It is anticipated that
the approval process can be completed by the end of 1999.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or elsewhere in this
annual report) which are not statements of historical fact are intended to be,
and are hereby identified as, "forward looking statements" for purposes of the
safe harbor provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties, and that actual
results could differ materially from those indicated by such forward-looking
statements. Important factors that could cause actual results to differ
materially from those indicated by such forward-looking statements include, but
are not limited to, the following: (1) that the information is of a preliminary
nature and may be subject to further and/or continuing review and adjustment,
(2) changes in the utility regulatory environment, including the pace of
deregulation of retail natural gas and electricity markets in the United
Sates,(3) changes in the economy in areas served by SCE&G, (4) the impact of
competition from other energy suppliers, (5) the management of SCE&G's
operations, (6) variations in prices of natural gas and fuels used for electric
generation,(7) growth opportunities, (8) the results of financing efforts, (9)
changes in SCE&G's accounting policies, (10) weather conditions, (11) inflation,
(12)exposure to environmental issued and liabilities, (13) changes in
environmental regulation, (14) successful correction of any material Year 2000
problem or, alternatively, successful implementation of a contingency plan by
SCE&G and any critical third party suppliers and (15) the other risks and
uncertainties described from time to time in SCE&G's periodic reports filed with
the SEC. SCE&G disclaims any obligation to update any forward-looking
statements.
COMPETITION
The electric utility industry continues a major transition that is
resulting in expanded market competition and less regulation. Deregulation of
electric wholesale and retail markets is creating 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. Legislative initiatives at
the Federal and state levels are being considered and, if enacted, could mandate
market deregulation. The pace of deregulation, the future prices of electricity,
and the regulatory actions which may be taken by the PSC and the FERC in
response to the changing environment cannot be predicted. However, the FERC, in
issuing Order 888 in April 1996, accelerated competition among electric
utilities by providing for open access to wholesale transmission service. Order
888 requires utilities under FERC jurisdiction that own, control or operate
transmission lines to file nondiscriminatory open access tariffs that offer to
others the same transmission service they provide themselves. The FERC has also
permitted utilities to seek recovery of wholesale stranded costs from departing
customers by direct assignment. Approximately two percent of SCE&G's electric
revenue is under FERC jurisdiction for the purpose of setting rates for
wholesale service. Legislation is pending in South Carolina that would
deregulate the state's retail electric market and enable customers to choose
their supplier of electricity. SCE&G is not able to predict whether the
legislation will be enacted and, if it is, the conditions it will impose on
utilities that currently operate in the state and future market participants.
SCE&G and its parent company, SCANA, are aggressively pursuing actions to
position themselves strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, one of SCANA's subsidiaries,
Energy Marketing, is aggressively marketing natural gas to residential and
commercial customers in Georgia's newly deregulated natural gas market.
Management believes that successfully competing in the Georgia market will
provide necessary experience and potential market share for a deregulated
electric industry. In addition, SCE&G has undertaken a variety of initiatives,
including reductions in staffing levels and the accelerated recovery of its
electric regulatory assets. SCE&G has also established open access transmission
tariffs and is selling bulk power to wholesale customers at market-based rates.
A significant new management information system was implemented in 1998, and a
new customer information system will be fully implemented in the first half of
1999. Marketing of services to commercial and industrial customers has increased
significantly. SCE&G has obtained long term power supply contracts with a
significant portion of its industrial customers. 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.
Regulated public utilities are allowed to record as assets some costs
that would be expensed by other enterprises. If deregulation or other changes in
the regulatory environment occur, SCE&G no longer be eligible to apply this
accounting treatment and may be required to eliminate such regulatory assets
from its balance sheet. Although the potential effects of deregulation cannot be
determined at present, discontinuation of the accounting treatment could have a
material adverse effect on SCE&G's results of operations in the period the
write-off is recorded. It is expected that cash flows and the financial position
of SCE&G would not be materially affected by the discontinuation of the
accounting treatment. SCE&G reported approximately $208 million and $66 million
of regulatory assets and liabilities, respectively, including amounts recorded
for deferred income tax assets and liabilities of approximately $123 million and
$51 million, respectively, on its balance sheet at December 31, 1998.
SCE&G's generation assets are exposed to considerable financial risks in
a deregulated electric market. If market prices for electric generation do not
produce adequate revenue streams and the enabling legislation or regulatory
actions do not provide for recovery of the resulting stranded costs, SCE&G could
be required to write down its investment in these assets. SCE&G cannot predict
whether any write-downs will be necessary and, if they are, the extent to which
they would adversely affect SCE&G's results of operations in the period in which
they are recorded. As of December 31, 1998, SCE&G's net investment in
fossil\hydroelectric generation and nuclear generation assets was $1,033.9
million and $619.2 million, respectively.
LIQUIDITY AND CAPITAL RESOURCES
The cash requirements of SCE&G arise primarily from its operational needs
and construction program. The ability of SCE&G to replace existing plant
investment, as well as to expand to meet future demand for electricity and gas,
will depend upon its ability to attract the necessary financial capital on
reasonable terms. SCE&G recovers the costs of providing services through rates
charged to customers. Rates for regulated services are generally based on
historical costs. As customer growth and inflation occur and SCE&G continues its
ongoing construction program, it may be necessary to seek increases in rates. As
a result, SCE&G's future financial position and results of operations will be
affected by its ability to obtain adequate and timely rate and other regulatory
relief, if requested.
SCANA and Westvaco each own a 50% interest in Cogen South LLC (Cogen).
Cogen was formed to build and operate a cogeneration facility at Westvaco's
Kraft Division Paper Mill in North Charleston, South Carolina. Construction of
the facility began in September 1996 is in the final stages. Construction
financing of approximately $170 million was provided to Cogen by banks. On
September 10, 1998 the contractor in charge of construction filed suit in
Circuit Court seeking approximately $51 million from Cogen, alleging that
construction cost overruns were incurred, and that the construction contract
provides for recovery of these costs. In addition to Cogen, Westvaco, SCE&G and
SCANA were also named in the suit. SCE&G and the other defendants believe the
suit is without merit and are mounting an appropriate defense. SCE&G does not
believe that the resolution of this issue will have a material impact on its
results of operations, cash flows or financial position.
On August 7, 1996 the City of Charleston executed 30-year electric and
gas franchise agreements with SCE&G. In consideration for the electric franchise
agreement, SCE&G is paying the City $25 million over seven years (1996-2002) and
has donated to the City the existing transit assets in Charleston. The $25
million is included in electric plant-in-service. In settlement of environmental
claims the City may have had against SCE&G involving the Calhoun Park area,
where SCE&G and its predecessor companies operated a manufactured gas plant
until the 1960's, SCE&G is paying the City $26 million over a four-year period
(1996-1999). As part of the environmental settlement, SCE&G has agreed to
construct an 1,100 space parking garage on the Calhoun Park site and to transfer
the facility to the City in exchange for a 20-year municipal bond backed by
revenues from the parking garage and a mortgage on the parking garage. The total
amount of the bond is not to exceed $16.9 million, the maximum expected project
cost. The parking garage is currently under construction, and is scheduled for
completion in the spring of the year 2000.
The revised estimated primary cash requirements for 1999, excluding
requirements for fuel liabilities and short-term borrowings and including notes
payable to affiliated companies, and the actual primary cash requirements for
1998 are as follows:
1999 1998
- -----------------------------------------------------------------------
(Millions of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $242 $231
Nuclear fuel expenditures 5 23
Maturing obligations, redemptions and
sinking and purchase fund requirements 81 61
- ----------------------------------------------------------------------
Total $328 $315
======================================================================
Approximately 78% of total cash requirements (after payment of
dividends) was provided from internal sources in 1998 as compared to 69% in
1997.
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
twelve consecutive months out of the fifteen months prior to the month of
issuance are at least twice the annual interest requirements on all Class A
Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1998 the
Bond Ratio was 5.30. The issuance of additional Class A Bonds also is restricted
to an additional principal amount equal to (i) 60% of unfunded net property
additions (which unfunded net property additions totaled approximately $396
million at December 31, 1998), (ii) retirements of Class A Bonds (which
retirement credits totaled $100.3 million at December 31, 1998), and (iii) cash
on deposit with the Trustee.
SCE&G has a bond indenture dated April 1, 1993 (New Mortgage) covering
substantially all of its electric properties under which its future
mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the
New Mortgage on the basis of a like principal amount of Class A Bonds issued
under the Old Mortgage which have been deposited with the Trustee of the New
Mortgage (of which $315 million were available for such purpose as of December
31, 1998), until such time as two-thirds of all Class A Bonds are held by the
Trustee. Thereafter, the Old Mortgage may be amended to allow New Bonds to be
issuable on the basis of property additions in a principal amount equal to 70%
of the original cost of electric and common plant properties (compared to 60% of
value for Class A Bonds under the Old Mortgage), cash deposited with the
Trustee, and retirement of New Bonds. New Bonds will be issuable under the New
Mortgage only if adjusted net earnings (as therein defined) for twelve
consecutive months out of the eighteen months immediately preceding the month of
issuance are at least twice the annual interest requirements on all outstanding
bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond
Ratio). For the year ended December 31, 1998 the New Bond Ratio was 6.72.
SCE&G expects in 1999 to amend the Old Mortgage to conform certain of
its provisions to those of the New Mortgage, including (i) the elimination of
the maintenance and replacement fund and the utilization of unfunded net
property additions previously applied in satisfaction thereof as a basis for the
issuance of bonds; (ii) the issuance of bonds in a principal amount equal to 70%
of unfunded net property additions instead of 60%; and (iii) the conformance of
the interest coverage requirements for the issuance of bonds to those of the New
Mortgage.
On November 2, 1998, SCE&G redeemed, prior to maturity, all $30 million
principal amount outstanding of its 7.25% series First and Refunding Mortgage
Bonds due January 1, 2002.
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; however,
no such consent is 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 must obtain
FERC authority to issue short-term debt. The FERC has authorized SCE&G to issue
up to $250 million of unsecured promissory notes or commercial paper with
maturity dates of twelve months or less, but not later than December 31, 2001.
At December 31, 1998 SCE&G had $285 million of authorized lines of
credit which includes a credit agreement for a maximum of $250 million to
support the issuance of commercial paper. Unused lines of credit at December 31,
1998 totaled $285 million. SCE&G's commercial paper outstanding at December 31,
1998 and December 31, 1997 was $125.2 million and $13.3 million, respectively.
In addition, Fuel Company has a credit agreement for a maximum of $125 million
with the full amount available at December 31, 1998. The credit agreement
supports the issuance of short-term commercial paper for the financing of
nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company
commercial paper outstanding at December 31, 1998 was $66.0 million. This
commercial paper and amounts outstanding under the revolving credit agreement,
if any, are guaranteed by SCE&G.
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 twelve consecutive
months immediately preceding the month of issuance are at least one and one-half
times the aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended December 31, 1998 the
Preferred Stock Ratio was 2.27.
SCE&G anticipates that its 1999 cash requirements of $474 million will
be met through internally generated funds (approximately 65%, after payment of
dividends) and the incurrence of additional short-term and long-term
indebtedness. SCE&G expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the next twelve months and
for the foreseeable future.
Environmental Matters
The Clean Air Act requires electric utilities to reduce emissions of
sulfur dioxide and nitrogen oxide substantially by the year 2000. These
requirements are being phased in over two periods. The first phase had a
compliance date of January 1, 1995 and the second, January 1, 2000. SCE&G's
facilities did not require modifications to meet the requirements of Phase I.
SCE&G will most likely meet the Phase II requirements through the burning of
natural gas and/or lower sulfur coal in its generating units and the purchase
and use of sulfur dioxide emission allowances. Low nitrogen oxide burners are
being installed to reduce nitrogen oxide emissions to the levels required by
Phase II. Air toxicity regulations for the electric generating industry are
likely to be promulgated around the year 2000.
SCE&G filed compliance plans with DHEC related to Phase II sulfur
dioxide requirements in 1995, and Phase II nitrogen oxide requirements in 1997.
SCE&G currently estimates that air emissions control equipment will require
capital expenditures of $121 million over the 1999-2003 period to retrofit
existing facilities, with increased operation and maintenance cost of
approximately $10 million per year. To meet compliance requirements through the
year 2008, SCE&G anticipates total capital expenditures of approximately $154
million.
On September 24, 1998, the United States Environmental Protection
Agency (EPA) issued its final regional nitrogen oxide state implementation plan
(SIP) call rule. The rule finds that 22 eastern states, including South
Carolina, and the District of Columbia are all contributing significantly to
ozone non-attainment in downwind states. In response to that finding, EPA is
requiring that those 22 states amend their SIP's to achieve significant
reductions in ozone emissions within those states, and has targeted primarily
utility sources for the application for more rigorous nitrogen oxide emissions
controls. A number of states, including South Carolina ,and other parties,
including a utility coalition of which SCE&G is a member, have filed suit in
federal court to challenge the EPA rule. Should the rule be upheld, SCE&G may be
required to make significant capital expenditures to add supplemental nitrogen
oxide control technology to one or more of its fossil generation plants.
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 generating units. Concurrent with
renewal of these permits, the permitting agency has implemented a more rigorous
program in monitoring and controlling thermal discharges and strategies for
toxicity reduction in wastewater streams. SCE&G has been developing compliance
plans for these initiatives.
In 1998 DHEC promulgated regulations for the disposal of industrial
solid waste as directed by the South Carolina Solid Waste Policy and Management
Act of 1991. The full impact of these regulations is not yet known; however,
they may significantly increase SCE&G's costs of construction and operation of
existing and future ash management facilities.
SCE&G has an environmental assessment program to identify and assess
current and former operations sites that could require environmental cleanup. As
site assessments are initiated, estimates are made of the expenditures, if any,
deemed necessary to investigate and clean up each site. These estimates are
refined as additional information becomes available; therefore, actual
expenditures could differ significantly from the original estimates. Amounts
estimated and accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts are deferred and amortized with recovery
provided through rates. SCE&G has also recovered portions of its environmental
liabilities through settlements with various insurance carriers. As of December
31, 1998, SCE&G has recovered all amounts previously deferred for its electric
operations. SCE&G expects to recover all deferred amounts related to its gas
operations by December 2002. Deferred amounts, net of amounts recovered through
rates and insurance settlements, totaled $21.3 million and $32.4 million at
December 31, 1998 and 1997, respectively. The deferral includes the estimated
costs to be associated with the matters discussed below.
o 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 encompasses approximately 30 acres and
includes properties which were locations for industrial operations,
including a wood preserving (creosote) plant, one of SCE&G's
decommissioned manufactured gas plants, properties owned by the
National Park Service and the City of Charleston, and private
properties. The site has not been placed on the National Priorities
List, but may be added in the future. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope of Work.
Field work began in November 1993, and the EPA approved a Remedial
Investigation Report in February 1997 and a Feasibility Study Report
in June 1998. In July 1998, the EPA approved SCE&G's Removal Action
Work Plan for soil excavation. SCE&G completed Phase One of the
Removal Action in 1998 at a cost of approximately $1.5 million. Phase
Two will include excavation and installation of several permanent
barriers to mitigate coal tar seepage. Phase Two began in November
1998, and is expected to cost approximately $2.2 million. On September
30, 1998 a Record of Decision was issued which sets forth the EPA's
view of the extent of each PRP's responsibility for site contamination
and the level to which the site must be remediated. On January 13,
1999 the EPA issued a Unilateral Administrative Order for Remedial
Design and Remedial Action directing SCE&G to design and carry out a
plan of remediation for the Calhoun Park site. The Order is
temporarily stayed pending further negotiations between SCE&G and the
EPA.
In October 1996 the City of Charleston and SCE&G settled all
environmental claims the City may have had against SCE&G
involving the Calhoun Park area for a payment of $26 million
over four years (1996-1999) by SCE&G to the City. SCE&G is
recovering the amount of the settlement, which does not
encompass site assessment and cleanup costs, through rates in
the same manner as other amounts accrued for site assessments
and cleanup as discussed above. As part of the environmental
settlement, SCE&G has agreed to construct an 1,100 space parking
garage on the Calhoun Park site and to transfer the facility to
the City in exchange for a 20-year municipal bond backed by
revenues from the parking garage and a mortgage on the parking
garage. The total amount of the bond is not to exceed $16.9
million, the maximum expected project cost. The parking garage
is currently under construction, and is scheduled for completion
in the spring of the year 2000.
o SCE&G owns three other decommissioned manufactured gas plant sites
which contain residues of by-product chemicals. For the site located
in Sumter, South Carolina, effective September 15, 1998, SCE&G entered
into a Remedial Action Plan Contract with DHEC pursuant to which it
agreed to undertake a full site investigation and remediation under
the oversight of DHEC. Site investigation and characterization are
proceeding according to schedule. Upon selection and successful
implementation of a site remedy, DHEC will give SCE&G a Certificate of
Completion, and a covenant not to sue. SCE&G is continuing to
investigate the other two sites, and is monitoring the nature and
extent of residual contamination.
Regulatory Matters
On December 11, 1998, the PSC issued an order requiring SCE&G to reduce
retail electric rates on a prospective basis. The PSC acted in response to SCE&G
reporting that it earned a 13.04% return on common equity for its retail
electric operations for the twelve months ended September 30, 1998. This return
on common equity exceeded SCE&G's authorized return of 12.0% by 1.04%, or $22.7
million, primarily as a result of record-breaking heat experienced during the
summer. The order requires prospective rate reductions on a per kilowatt-hour
basis, based on actual retail sales for the twelve months ended September 30,
1998. This action will reduce future reported return on common equity to the
Commission-authorized level if SCE&G experiences the same weather effect and
other business results as that of the twelve months ended September 30, 1998.
The order requires the rate reductions to be placed into effect with the first
billing cycle of January 1999. On December 21, 1998, SCE&G filed a motion for
reconsideration with the PSC. On January 12, 1999, the PSC denied SCE&G's motion
for reconsideration and reaffirmed SCE&G's return on equity of 12.0%.
On January 9, 1996 the PSC issued an order granting SCE&G an increase in
retail electric rates of 7.34%, which was designed to produce additional
revenues, based on a test year, of approximately $67.5 million annually. The
increase was implemented in two phases. The first phase, an increase in revenues
of approximately $59.5 million annually, or 6.47%, commenced in January 1996.
The second phase, an increase in revenues of approximately $8.0 million
annually, or .87%, was implemented in January 1997. The PSC authorized a return
on common equity of 12.0%. The PSC also approved establishment of a Storm Damage
Reserve Account capped at $50 million to be collected through rates over a
ten-year period. Additionally, the PSC approved accelerated recovery of a
significant portion of SCE&G's electric regulatory assets (excluding deferred
income tax assets) and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods to allow
recovery by the end of the year 2000. SCE&G's request to shift, for rate-making
purposes, approximately $257 million of depreciation reserves from transmission
and distribution assets to nuclear production assets was also approved. The
Consumer Advocate and two other intervenors appealed certain issues in the order
initially to the Circuit Court, which affirmed the PSC's decisions, and,
subsequently, to the Supreme Court. In March 1998, SCE&G, the PSC, the Consumer
Advocate and one of the other intervenors reached an agreement that provided for
the reversal of the shift in depreciation reserves and the dismissal of the
appeal of all other issues. The PSC also authorized SCE&G to adjust depreciation
rates that had been approved in the 1996 rate order for its electric
transmission, distribution and nuclear production properties to eliminate the
effect of the depreciation reserve shift and to retroactively apply such
depreciation rates to February 1996. As a result, a one-time reduction in
depreciation expense of $5.5 million after taxes was recorded in March 1998. The
agreement does not affect retail electric rates. FERC had previously rejected
the transfer of depreciation reserves for rates subject to its jurisdiction. In
September 1998, the Supreme Court affirmed the Circuit Court's rulings on the
issues contested by the remaining intervenor.
SCE&G's regulated business operations were impacted by the NEPA and FERC
Orders No. 636 and 888. NEPA was 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. See "Competition" for a discussion of FERC Order 888.
Order No. 636 was 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 SCE&G, it continues to be
able to meet successfully the challenges of these altered business climates and
does not anticipate any material adverse impact on the results of operations,
cash flows, financial position or business prospects.
Year 2000 Issue
The Year 2000 is an issue because many computers, embedded systems and
software were originally programmed using two digits rather than four digits to
identify the applicable year. This may prevent them from accurately processing
information with dates beyond 1999. Because the Year 2000 issue could have a
material impact on the operations of SCE&G if not addressed, SCE&G's goal is to
be Year 2000 ready. This means that before the year 2000, critical systems,
equipment, applications and business relationships will have been evaluated and
should be suitable to continue into and beyond the year 2000 and that applicable
contingency plans are in place.
In 1993, SCE&G began the first of several projects to replace many of its
business application systems to provide increased functionality and to improve
access to business information. Accordingly, SCE&G has implemented new general
ledger, purchasing, materials inventory and accounts payable systems, and is
currently implementing a new customer information system. The new customer
information system is being phased into production by geographical area, and
should be fully implemented in the first half of 1999. These new systems, which
comprise a significant portion of SCE&G's application software, are designed to
be Year 2000 compliant, and therefore mitigate overall Year 2000 exposure.
In 1997, SCANA established a Corporate Year 2000 Project Office (Project
Office) to direct Year 2000 efforts for itself and each of its subsidiaries,
including SCE&G. A Steering Committee was formed to direct the efforts of the
Project Office. The Steering Committee reports to the senior officers of the
Company and its board of directors. It is chaired by the Company's chief
financial officer, and is comprised of officers representing all operational
areas. The Project Office is staffed by nine full time project managers and
extensive support personnel. The Project Office is responsible for addressing
Year 2000 issues and coordinating the required assessment and remediation
efforts.
The Company's Year 2000 efforts encompass three projects, all reporting
to the Steering Committee. The Information Technology Project covers all
mainframe and client server application software, infrastructure hardware,
system software, desktop computers and network equipment. The Embedded Systems
Project covers all microprocessors, instrument and control devices, monitoring
equipment on power lines and in substations, security and control devices,
telephone systems and certain types of meters. The Procedures and External
Interfaces Project covers Year 2000 procedures, documentation and communications
with key suppliers, vendors, customers, financial institutions and governmental
agencies.
The Company's Year 2000 project approach involves the following: (1)
inventorying all Year 2000 internal and external items and entities and updating
the Year 2000 Inventory Database; (2) performing risk analysis and corporate
prioritization of all inventory entries; (3) performing detailed assessments of
all inventory entries to determine Year 2000 readiness and establishing a
remediation action plan where necessary; (4) remediating all inventory entries
assessed as non-compliant, including repairing, replacing or developing
acceptable work-arounds; (5) testing through date simulation and comprehensive
test data (6) implementation of all converted systems and equipment into
production operations; and (7) contingency planning.
Detailed project plans exist for each of the Year 2000 projects. These
project plans, work schedules and resource requirements are reviewed weekly by
the project managers and monthly by the Steering Committee. The Year 2000
projects, which will address SCE&G's critical systems and business
relationships, are appropriately staffed and are currently on schedule to be
completed by July 1999. As reported to the North American Electric Reliability
Council (NERC) in January 1999, the Company was 100% complete with inventory
tasks, 63% complete with detailed assessment tasks and 58% complete with
remediation tasks.
The Information Technology Project Team has completed the assessment and
initial code remediation for all application software. Most of the applications
have been tested in an isolated Year 2000 testing environment and the rest are
being tested according to the project schedule. The assessment of the technical
infrastructure and desktop computing environment is complete and required
remediation is in process. Testing of all network equipment is in process. The
Information Technology Project was approximately 55% complete through December
1998.
The Embedded Systems Project Team, which includes approximately 20
engineers with prior experience with microprocessors, was formed, and detailed
assessment, remediation and testing procedures were developed. This team is
currently working closely with each of the Company's business units to complete
the assessments of critical systems and equipment based on the corporate
prioritization process. An Embedded Systems Audit Review Committee has been
established to review all assessments for critical systems. As assessments are
completed, any required remediation efforts are evaluated and implemented.
Independent verifications for selected completed assessments are planned during
the first quarter of 1999. The Embedded Systems Project was approximately 50%
complete through December 1998.
The Procedures and External Interfaces Project Team has developed written
documentation and procedures for Year 2000 compliance definition, document
control, inventory, prioritization, assessment, remediation, change control,
business continuity planning, and vendor and supplier communications. This team
is coordinating communications with all significant vendors and suppliers in an
attempt to determine the extent to which the Company may be vulnerable to their
failure to remediate their own Year 2000 issues. The Company has completed an
initial survey of vendors and is currently evaluating the responses to those
surveys and conducting additional inquiries where necessary. The Company is also
in the process of evaluating critical third party service providers to ascertain
their Year 2000 readiness. The Company has developed communications materials
explaining its year 2000 efforts and is continuing communications with
significant customers and external groups, including the PSC. The Procedures and
External Interfaces Project was approximately 45% complete through December
1998.
SCE&G has projected the total cost of its Year 2000 efforts to be
approximately $19 million. The table below outlines the anticipated timing and
breakdown of these expenditures:
- ---------------------------------------------------------------------------
Internal Out of Pocket Total
- ---------------------------------------------------------------------------
Project To Date $ 2 $ 6 $ 8
1999 3 8 11
--- ---- ---
Total $ 5 $ 14 $19
- ---------------------------------------------------------------------------
The cost of the project is based on management's best estimates, which
are based on assumptions regarding future events. These future events include
continued availability of key resources, third parties' Year 2000 readiness and
other factors. The cost of the project is not expected to have a material impact
on the results of operations or on the financial position or cash flows of
SCE&G. The costs of implementing the new business application systems referred
to earlier are not included in these cost estimates.
A failure to correct a material Year 2000 problem by SCE&G or by a
critical third party supplier could result in an interruption in, or a failure
of SCE&G's ability to provide energy services. At this time, SCE&G believes its
most reasonably likely worst case scenario is that Year 2000 failures could lead
to temporary reduced generating capacity on SCE&G's electrical grid, temporary
intermittent interruptions in communications and temporary intermittent
interruptions in gas supply from interstate suppliers or producers. A Year 2000
problem of this nature could result in temporary interruptions in electric or
gas service to our customers. SCE&G has no historical experience with
interruptions caused by this scenario. However, these temporary interruptions in
service, if any, might be similar to weather-related outages that SCE&G
encounters from time to time in its business today. Although SCE&G does not
believe that this scenario will occur, SCE&G is enhancing existing contingency
plans to ensure preparedness and to mitigate the long term effect of such a
scenario. Since the expected impact of this scenario on SCE&G's operations, cash
flow and financial position cannot be determined, there is no assurance that it
would not be material.
SCE&G has established eight business continuity planning task groups to
develop Year 2000 business continuity plans. These task groups have developed
initial draft plans to cover SCE&G's Corporate Operations, Customer Service
Operations, Electric Generation, Transmission and Distribution Operations, Gas
Delivery Operations, Telecommunications and Emergency Preparedness, Information
Technology and Procurement. Detailed contingency plans that were already in
place to cover weather-related outages, computer failures and generation outages
were used and/or referenced as the basis for the initial draft Year 2000
business continuity plans. The initial draft plans are continuing to be
enhanced, and where necessary, new plans will be developed to include mitigation
strategies and emergency response action plans to address potential Year 2000
scenarios and critical system failures. The final plans will also include
mitigation strategies to address reliance on critical suppliers.
NERC is coordinating Year 2000 efforts of the electric utility industry
in the United States and contingency planning within the regional electric
reliability councils. Coordination in SCE&G's region is through the Southeastern
Electric Reliability Council (SERC). SCE&G's contingency planning efforts are in
compliance with the SERC and NERC contingency planning guidelines which required
draft contingency plans to be complete by December 31, 1998 and will require
final contingency plans to be complete by June 30, 1999.
In addition to NERC and SERC, SCE&G is working with the Electric Power
Research Institute to address the issue of overall grid reliability and
protection. To ensure that all Year 2000 issues at its Summer Station nuclear
plant are addressed, SCE&G is closely cooperating with other utility companies
that own nuclear power plants. The utilities are sharing technical nuclear plant
operating and monitoring systems information to ensure the prompt and effective
resolution of the year 2000 issue.
Subsequent Event
On March 9, 1999, SCE&G issued $100 million First Mortgage Bonds due
March 1, 2009 at an interest rate of 6.125%. The funds were issued to reduce
short-term debt.
RESULTS OF OPERATIONS
Net Income
Net income and the percent increase from the previous year for the years
1998, 1997 and 1996 were as follows:
1998 1997 1996
- --------------------------------------------------------------------------
(Millions of Dollars)
Net income $227.2 $194.7 $190.5
Percent increase in net
income 16.72% 2.19% 12.59%
- --------------------------------------------------------------------------
o 1998 Net income increased for the year primarily as a result of
more favorable weather and customer growth which more than offset
the impact of higher operating costs. In addition, net income
includes a one-time, after-tax reduction to depreciation expense
of approximately $5.5 million related to a change in depreciation
rates retroactive to February 1996. This change in rates results
from the reversal of a $257 million shift of depreciation reserves
from electric transmission and distribution assets to nuclear
production assets, previously approved in a PSC rate order in
January 1996. See "Liquidity and Capital Resources."
o 1997 Net income increased for the year primarily as a result of
increases in gas sales margins.
SCE&G'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 3.8% of income before income taxes in
1998, 4.0% in 1997 and 3.2% in 1996.
Electric Operations
Electric operations sales margins for 1998, 1997 and 1996 were as follows:
1998 1997 1996
- --------------------------------------------------------------------------
(Millions of Dollars)
Operating revenues $1,219.8 $1,103.1 $1,106.7
Less: Fuel used in generation 212.3 181.0 187.1
Purchased power 116.4 109.2 106.8
- --------------------------------------------------------------------------
Margin $ 891.1 $ 812.9 $ 812.8
==========================================================================
o 1998 The sales margin increased for 1998 primarily due to more favorable
weather and customer growth.
o 1997 The sales margin increased slightly due to the favorable
impact of the rate increase placed into effect in January 1997 and
economic growth factors which were offset by the effect of milder
weather.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes were as follows:
Classification 1998 1997
- ---------------------------------------------------------------------
Residential 676,578 (292,518)
Commercial 577,852 99,221
Industrial 389,931 113,716
Sales for Resale (excluding interchange) 65,367 36,894
Other 29,823 15
- ----------------------------------------------------------------------
Total territorial 1,739,551 (42,672)
Negotiated Market Sales Tariff 610,784 (10,818)
- ----------------------------------------------------------------------
Total 2,350,335 (53,490)
=====================================================================
o 1998 The sales volume increases for 1998 were primarily due to more favorable
weather and customer growth.
o 1997 The sales volume for residential sales decreased for 1997 as a result
of milder weather.
Gas Distribution
Gas distribution sales margins for 1998, 1997 and 1996 were as follows:
1998 1997 1996
- ---------------------------------------------------------------------
(Millions of Dollars)
Operating revenues $230.4 $233.6 $234.8
Less: Gas purchased for resale 142.4 151.9 157.1
- ---------------------------------------------------------------------
Margin $ 88.0 $ 81.7 $ 77.7
=====================================================================
o 1998 The sales margin increased over 1997 due to renegotiation of
industrial customers' contracts, lower gas prices and increased
sales to electric generation facilities.
o 1997 The sales margin increased over the prior year primarily as a
result of increases in contract prices and sales to industrial
interruptible customers.
Increases (decreases) from the prior year in dekatherm (DT) sales volume by
classes, including transportation gas, were as follows:
Classification 1998 1997
- -----------------------------------------------------------------
Residential (2,685) (2,188,215)
Commercial 389,468 (123,385)
Industrial 2,363,341 1,820,166
Transportation gas (673,795) (430,610)
- -----------------------------------------------------------------
Total 2,076,329 (922,044)
=================================================================-
o 1998 The sales volume for commercial and industrial customers
increased, and transportation decreased, for 1998 as a result of lower
gas prices and increased sales to electric generation facilities.
o 1997 The sales volume for residential customers decreased for 1997 as
a result of milder weather which was partially offset by increases in
sales to industrial interruptible customers.
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including taxes, were as
follows:
Classification 1998 1997
- ------------------------------------------------------------------
(Millions of Dollars)
Other operation and maintenance $27.4 $ 3.0
Depreciation and amortization (9.0) 4.7
Income taxes 29.9 (9.7)
Other taxes 5.6 8.1
- ------------------------------------------------------------------
Total $53.9 $ 6.1
==================================================================
o 1998 Other operation and maintenance expenses increased primarily due
to increased maintenance costs for electric generation and
distribution facilities, various other electric operating costs and
Year 2000 testing and remediation. The decrease in depreciation and
amortization expense reflects the non-recurring adjustment to
depreciation expense discussed under Net Income. The increase in
income tax expense primarily reflects changes in operating income.
The increase in other taxes primarily results from increased property
taxes.
o 1997 Other operation and maintenance expenses increased somewhat from
1996 levels. A decrease in transit operating costs resulting from
SCE&G's transfer of the ownership of the Charleston transit system to
the City of Charleston in October 1996 largely offset increases in
costs at electric generating plants and other operating costs. The
increase in depreciation and amortization expenses for 1997 reflects
the additions to plant-in-service. The change in income tax expense is
primarily due to a change in pre-tax operating income and the
difference between estimated income taxes accrued and actual income
tax expense per the tax returns as filed. The increase in other taxes
results primarily from the accrual of additional property taxes,
beginning in January 1997, related to the Cope plant and other
property additions which was partially offset by a reduction in the
1997 property tax assessment. Recovery of the Cope plant property
taxes is provided for in a retail electric rate increase that became
effective January 1997.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
Classification 1998 1997
- ------------------------------------------------------------------------------
(Millions of Dollars)
Interest on long-term debt, net $(1.4) $(0.1)
Other interest expense 1.3 2.7
- ------------------------------------------------------------------------------
Total $(0.1) $ 2.6
==============================================================================
There was no material change in interest expense from 1997 to 1998, or 1996
to 1997.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations, the table presents principal cash flows and related weighted
average interest rates by expected maturity dates.
December 31, 1998
Expected Maturity Date
(Millions of Dollars)
There- Fair
Liabilities 1999 2000 2001 2002 2003 after Total Value
--------------------------------------------------------
Long-Term Debt:
Fixed Rate ($) 29.1 188.6 22.6 22.6 124.5 943.4 1,330.6 1,356.4
Average Interest Rate 6.56 5.89 6.72 6.72 7.56 7.77 7.38
While a decrease in interest rates would increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditors' Report............ ........................ 79
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1998 and 1997......... 80
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1998, 1997 and 1996.................. 82
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996... 83
Consolidated Statements of Capitalization as of
December 31, 1998 and 1997 .................. 84
Notes to Consolidated Financial Statements............................ 86
Information required to be disclosed in supplemental financial statement
schedules is included in the consolidated financial statements or in the notes
thereto.
INDEPENDENT AUDITORS' REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and Statements of
Capitalization of South Carolina Electric & Gas Company (Company) as of December
31, 1998 and 1997 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, 1998. 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, 1998
and 1997 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 8 , 1999
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1998 1997
- ------------------------------------------------------------------------------
(Millions of Dollars)
ASSETS
Utility Plant (Notes 1, 3 and 4):
Electric $4,133 $4,020
Gas 366 353
Other 175 84
- ------------------------------------------------------------------------------
Total 4,674 4,457
Less accumulated depreciation and amortization 1,517 1,421
- ------------------------------------------------------------------------------
Total 3,157 3,036
Construction work in progress 219 221
Nuclear fuel, net of accumulated amortization 56 53
- ------------------------------------------------------------------------------
Utility Plant, Net 3,432 3,310
- ------------------------------------------------------------------------------
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 16 17
- ------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments (Note 8) 36 6
Receivables - customer and other 178 165
Inventories (At average cost):
Fuel (Notes 1, 3 and 4) 32 23
Materials and supplies 47 48
Prepayments 8 10
Deferred income taxes 21 21
- ------------------------------------------------------------------------------
Total Current Assets 322 273
- ------------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 22 32
Nuclear plant decommissioning fund (Note 1) 56 49
Pension asset, net (Note 1) 115 82
Other (Note 1) 252 260
- ------------------------------------------------------------------------------
Total Deferred Debits 476 454
- ------------------------------------------------------------------------------
Total $4,246 $4,054
==============================================================================
PAGE
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1998 1997
Millions of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment:
Common equity (Note 5) $1,499 $1,447
Preferred stock (Not subject to purchase or
sinking funds) 106 106
- --------------------------------------------------------------------------------
Total Stockholders' Investment 1,605 1,553
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 11 12
Company - Obligated Mandatorily Redeemable Preferred
Securities of the Company's Subsidiary Trust, SCE&G Trust I holding solely $50
million, principal amount of 7.55% of Junior Subordinated Debentures of the
Company,
due 2027 50 50
Long-Term Debt, Net (Notes 3, 4 and 8) 1,206 1,262
- --------------------------------------------------------------------------------
Total Capitalization 2,872 2,877
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 125 13
Current portion of long-term debt (Note 3) 29 48
Accounts payable 97 53
Accounts payable - affiliated companies (Notes 1 and 3) 23 32
Customer deposits 17 16
Taxes accrued 75 45
Interest accrued 21 22
Dividends declared 38 58
Other 10 7
- --------------------------------------------------------------------------------
Total Current Liabilities 435 294
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes (Notes 1 and 7) 549 539
Deferred investment tax credits (Notes 1 and 7) 100 89
Reserve for nuclear plant decommissioning (Note 1) 56 49
Postretirement benefits 87 61
Other (Note 1) 147 145
- --------------------------------------------------------------------------------
Total Deferred Credits 939 883
- --------------------------------------------------------------------------------
Total $4,246 $4,054
================================================================================
See Notes to Consolidated Financial Statements.
PAGE
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------
(Millions of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $1,220 $1,103 $1,107
Gas 230 234 235
Transit 1 1 3
- --------------------------------------------------------------------------------
Total Operating Revenues 1,451 1,338 1,345
- --------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 212 181 187
Purchased power (including affiliated
purchases)(Note 1) 116 109 107
Gas purchased from affiliate for resale (Note 1) 142 152 157
Other operation 239 222 222
Maintenance (Note 1) 79 67 64
Depreciation and amortization (Note 1) 131 140 135
Income taxes (Notes 1 and 7) 128 98 108
Other taxes 92 87 79
- --------------------------------------------------------------------------------
Total Operating Expenses 1,139 1,056 1,059
- --------------------------------------------------------------------------------
Operating Income 312 282 286
- --------------------------------------------------------------------------------
Other Income (Note 1):
Allowance for equity funds used during construction 7 6 4
Other income (loss), net of income taxes 6 3 -
- --------------------------------------------------------------------------------
Total Other Income 13 9 4
- --------------------------------------------------------------------------------
Income Before Interest Charges 325 291 290
- --------------------------------------------------------------------------------
Interest Charges (Credits):
Interest on long-term debt, net 95 96 97
Other interest expense (Notes 1 and 3) 6 5 7
Allowance for borrowed funds used
during construction (Note 1) (7) (6) (5)
- --------------------------------------------------------------------------------
Total Interest Charges, Net 94 95 99
- --------------------------------------------------------------------------------
Income Before Preferred Dividend Requirements on
Mandatorily Redeemable Preferred Securities 231 196 191
Preferred Dividend Requirement of
Company - Obligated Mandatorily Redeemable
Preferred Securities. 4 1 -
- --------------------------------------------------------------------------------
Net Income 227 195 191
Preferred Stock Cash Dividends (At stated rates) (8) (9) (6)
- --------------------------------------------------------------------------------
Earnings Available for Common Stock 219 186 185
Retained Earnings at Beginning of Year 438 415 366
Common Stock Cash Dividends Declared (Note 5) (166) (163) (136)
- --------------------------------------------------------------------------------
Retained Earnings at End of Year $ 491 $ 438 $ 415
================================================================================
See Notes to Consolidated Financial Statements.
85
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $ 227 $ 195 $ 190
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 131 140 135
Amortization of nuclear fuel 20 19 19
Deferred income taxes, net 49 16 32
Pension asset (33) (24) (23)
Postretirement benefits 26 24 16
Allowance for funds used during construction (14) (12) (9)
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (13) 6 (10)
(Increase) decrease in inventories (8) 8 1
Increase (decrease) in accounts payable 35 (13) -
Increase (decrease) in taxes accrued 30 (22) 3
Other, net (9) 31 (27)
- ------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 441 368 327
- ------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, net of AFC (252) (232) (209)
Increase in nonutility property and investments (1) (5) -
- ------------------------------------------------------------------------------
Net Cash Used For Investing Activities (253) (237) (209)
- ------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds and other
long-term debt - 1 -
Issuance of company - obligated mandatorily
redeemable trust preferred securities - 49 -
Equity contributions from parent - 12 49
Issuance of preferred stock - 99 -
Repayments:
Mortgage bonds (50) (15) (22)
Other long-term debt (11) - (1)
Preferred stock (1) (53) (3)
Repayment of bank loans - (10) (3)
Dividend Payments:
Common stock (187) (141) (133)
Preferred stock (7) (9) (5)
Short-term borrowings, net 112 (77) 10
Fuel and emission allowance financings, net (14) 14 (11)
- ------------------------------------------------------------------------------
Net Cash Used For Financing Activities (158) (130) (119)
- ------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Temporary Cash
Investments 30 1 (1)
Cash and Temporary Cash Investments, January 1 6 5 6
- ------------------------------------------------------------------------------
Cash and Temporary Cash Investments, December 31 $ 36 $ 6 $ 5
==============================================================================
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized
interest of $7, $6 and $5) $ 101 $ 98 $ 103
- Income taxes 92 (48) 102
Noncash Financing Activities:
Charleston Franchise Agreement - - 21
Charleston Environmental Agreement - - 20
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1998 1997
Common Equity (Note 5): (Millions of Dollars)
Common stock, 4.50 par value, authorized 50,000,000 shares; issued
and outstanding, 40,296,147 shares $ 181 $ 181
Premium on common stock 395 395
Other paid-in capital 437 438
Capital stock expense (5) (5)
Retained earnings 491 438
- -----------------------------------------------------------------------------------------------------------------
Total Common Equity 1,499 52% 1,447 50%
- ----------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (Not subject to purchase or sinking funds):
$100 Par Value - Authorized 1,200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Series 1998 1997
$100 Par 6.52% 1,000,000 1,000,000 100.00 100 100
$50 Par 5.00% 125,209 125,209 52.50 6 6
---------------------------------------------------------------------------------------------------------------
Total Preferred Stock (Not subject to purchase or sinking funds) 106 4% 106 4%
- ----------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and
8):
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 1998 and 1997
$50 Par Value - Authorized 1,580,052 shares
Shares Outstanding Redemption Price
Series 1998 1997
4.50% 12,800 14,400 51.00 1 1
4.60%(A) 20,052 21,894 51.00 1 1
4.60%(B) 64,600 68,000 50.50 3 4
5.125% 69,000 70,000 51.00 3 3
6.00% 73,600 76,800 50.50 4 4
-------------------
Total 240,052 251,094
===================
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1998 and 1997
Total Preferred Stock (Subject to purchase or sinking funds) 12 13
Less: Current portion, including sinking fund requirements 1 1
- ----------------------------------------------------------------------------------------------------------------
Total Preferred Stock, Net (Subject to purchase or sinking funds) 11 -% 12 -%
- ---------------------------------------------------------------------------------------------------------------
Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55% of
Junior Subordinated Debentures of the Company, due 2027. 50 2% 50 2%
- ---------------------------------------------------------------------------------------------------------------
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1998 1997
- ---------------------------------------------------------------------------------------------------
(Millions of Dollars)
Long-Term Debt (Notes 3, 4 and 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100 100
6 1/4% 2003 100 100
7.70% 2004 100 100
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
First and Refunding Mortgage Bonds:
Year of
Series Maturity
6 1/2% 1998 - 20
7 1/4% 2002 - 30
9% 2006 131 131
8 7/8% 2021 114 114
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984, due 2014 (6.50%) 57 57
Orangeburg County Series 1994 due 2024 (5.70%) 30 30
Other 16 16
Commercial Paper 66 80
Charleston Franchise Agreement due 1997-2002 14 18
Charleston Environmental Agreement due 1997-1999 6 13
Other 4 4
- ------------------------------------------------------------------------------------------------------
Total Long-Term Debt 1,238 1,313
Less: Current maturities, including sinking fund requirements 29 48
Unamortized discount 3 3
- ------------------------------------------------------------------------------------------------------
Total Long-Term Debt, Net 1,206 42% 1,262 44%
- -----------------------------------------------------------------------------------------------------
Total Capitalization $2,872 100% $2,877 100%
=====================================================================================================
See Notes to Consolidated Financial Statements.
106
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
South Carolina Electric & Gas Company (the Company), a public utility, is
a South Carolina corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation, a South Carolina holding company. The Company is engaged
predominately in the generation and sale of electricity to wholesale and retail
customers in South Carolina and in the purchase, sale and transportation of
natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements include the accounts
of the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust
I. Intercompany balances and transactions between the Company, Fuel Company and
SCE&G Trust I have been eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain affiliates to
purchase gas for resale to its distribution customers and to purchase electric
energy. The Company purchases all of its natural gas requirements from Pipeline
Corporation and at December 31, 1998 and 1997 the Company had approximately
$16.1 million and $22.1 million, respectively, payable to Pipeline Corporation
for such gas purchases. The Company purchases all of the electric generation of
Williams Station, which is owned by GENCO, under a unit power sales agreement.
At December 31, 1998 and 1997 the Company had approximately $5.8 million and
$9.1 million, respectively, payable to GENCO for unit power purchases. Such unit
power purchases, which are included in "Purchased power," amounted to
approximately $85.0 million, $99.8 million and $95.3 million in 1998, 1997 and
1996, respectively.
Total interest income, based on market interest rates, associated with
the Company's advances to affiliated companies was approximately $281,000,
$20,000 and $36,000 in 1998, 1997 and 1996, respectively.
In 1998, 1997 and 1996 there were no amounts relating to advances from
affiliated companies included in "Other interest expense."
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statements of Financial
Accounting Standards No. 71 (SFAS 71). The accounting standard requires
cost-based rate-regulated utilities to recognize in their financial statements
revenues and expenses in different time periods than do enterprises that are not
rate-regulated. As a result the Company has recorded, as of December 31, 1998,
approximately $208 million and $66 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets and
liabilities of approximately $123 million and $51 million, respectively. The
electric and gas regulatory assets of approximately $50 million and $33 million,
respectively (excluding deferred income tax assets) are being recovered through
rates and, as discussed in Note 2B, the PSC has approved accelerated recovery of
approximately $14 million of the electric regulatory assets. In the future, as a
result of deregulation or other changes in the regulatory environment, the
Company may no longer meet the criteria for continued application of SFAS 71 and
would be required to write off its regulatory assets and liabilities. Such an
event could have a material adverse effect on the Company's results of
operations in the period the write-off is recorded, but it is not expected that
cash flows or financial position would be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and as adopted by the South Carolina Public Service Commission
(PSC).
D. Utility Plant
Utility plant is stated substantially at original cost. The costs of
additions, renewals and betterments to utility plant, including direct labor,
material and indirect charges for engineering, supervision and an allowance for
funds used during construction, are added to utility plant accounts. The
original cost of utility property retired or otherwise disposed of is removed
from utility plant accounts and generally charged, along with the cost of
removal, less salvage, to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.
The Company, operator of the V. C. Summer Nuclear Station (Summer
Station), and Santee Cooper (formerly the South Carolina Public Service
Authority) are joint owners of Summer Station in the proportions of two-thirds
and one-third, respectively. The parties share the operating costs and energy
output of the plant in these proportions. Each party, however, provides its own
financing. Plant-in-service related to the Company's portion of Summer Station
was approximately $983.3 million and $978.2 million as of December 31, 1998 and
1997, respectively. Accumulated depreciation associated with the Company's share
of Summer Station was approximately $369.2 million and $323.6 million as of
December 31, 1998 and 1997, respectively. The Company's share of the direct
expenses associated with operating Summer Station is included in "Other
operation" and "Maintenance" expenses.
E. Allowance for Funds Used During Construction
AFC, a noncash item, reflects the period cost of capital devoted to plant
under construction. This accounting practice results in the inclusion of, as a
component of construction cost, the costs of debt and equity capital dedicated
to construction investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates for utility
services. The Company has calculated AFC using composite rates of 8.5%, 8.8% and
8.1% for 1998, 1997 and 1996, 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 incurred.
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 annual 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 annual fuel cost hearing. The Company had undercollected through
the electric fuel cost component approximately $3.1 million and $1.3 million at
December 31, 1998 and 1997, respectively, which are included in "Deferred Debits
- - Other."
Customers subject to the gas cost adjustment clause are billed based on a
fixed cost of gas determined by the PSC during annual gas cost recovery
hearings. Any difference between actual gas cost and that contained in the rates
is deferred and included when establishing gas costs during the next annual gas
cost recovery hearing. At December 31, 1998 and 1997 the Company had
undercollected through the gas cost recovery procedure approximately $5.2
million and $7.6 million, respectively, which are included in "Deferred Debits
Other."
The Company's gas rate schedules for residential, small commercial and
small industrial customers include a weather normalization adjustment, which
minimizes fluctuations in gas revenues due to abnormal weather conditions.
G. Depreciation and Amortization
Provisions for depreciation are recorded using the straight-line method
for financial reporting purposes and are based on the estimated service lives of
the various classes of property. The composite weighted average depreciation
rates were 3.02%, 3.09% and 3.13% for 1998, 1997 and 1996, respectively.
Nuclear fuel amortization, which is included in "Fuel used in electric
generation" and is recovered through the fuel cost component of the Company's
rates, is recorded using the units-of-production method. Provisions for
amortization of nuclear fuel include amounts necessary to satisfy obligations to
the Department Of Energy (DOE) 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.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently scheduled to commence when
the operating license expires in the year 2022. Based on a 1991 study, the
expenditures (on a before-tax basis) related to the Company's share of
decommissioning activities were estimated to be approximately $200 million,
including partial reclamation costs. The Company is providing for its share of
estimated decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning costs is referred to as
COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through
rates ($3.2 million in each of 1998 and 1997) are used to pay premiums on
insurance policies on the lives of certain Company personnel. The Company is the
beneficiary of these policies. Through these insurance contracts, the Company is
able to take advantage of income tax benefits and accrue earnings on the fund on
a tax-deferred basis. Amounts for decommissioning collected through electric
rates, insurance proceeds, and interest on proceeds less expenses are
transferred by the Company to an external trust fund in compliance with the
financial assurance requirements of the Nuclear Regulatory Commission.
Management intends for the fund, including earnings thereon, to provide for all
eventual decommissioning expenditures on an after-tax basis. The trust's sources
of decommissioning funds under the COMReP program include investment components
of life insurance policy proceeds, return on investment and the cash transfers
from the Company described above. The Company records its liability for
decommissioning costs in deferred credits.
Pursuant to the National Energy Policy Act passed by Congress in 1992 and
the requirements of the DOE, the Company has recorded a liability for its
estimated share of the DOE's decontamination and decommissioning obligation. The
liability, approximately $3.6 million at December 31, 1998, has been included in
"Long-Term Debt, Net." The Company is recovering the cost associated with this
liability through the fuel cost component of its rates; accordingly, this amount
has been deferred and is included in "Deferred Debits - Other."
I. Income Taxes
Deferred tax assets and liabilities are recorded for the tax effects of
temporary differences between the book basis and tax basis of assets and
liabilities at currently enacted tax rates. Deferred tax assets and liabilities
are adjusted for changes in such rates through charges or credits to regulatory
assets or liabilities if they are expected to be recovered from, or passed
through to, customers; otherwise, they are charged or credited to income tax
expense.
J. Pension Expense
The Company participates in SCANA's noncontributory defined benefit
pension plan, which covers 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. SCANA's policy has been to fund the
plan to the extent permitted by the applicable Federal income tax regulations as
determined by an independent actuary.
In addition to pension benefits, the Company provides certain health care
and life insurance benefits to active and retired employees. Retirees share in a
portion of their medical care cost. The Company provides life insurance benefits
to retirees at no charge. 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. Additionally, to accelerate the
amortization of the remaining transition obligation for postretirement benefits
other than pensions, as authorized by the PSC, the Company expensed
approximately $15.7 million, $15.6 million and $6.2 million for the years ended
December 31, 1998, 1997 and 1996, respectively. (See Note 2B.)
Disclosure required for these plans under Statement of Financial Accounting
Standards No. 132, "Employer's Disclosures about Pensions and Other
Postretirement Benefits" are set forth in the following tables:
Components of Net Periodic Benefit Cost
Other
Retirement Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
(Millions of Dollars) (Millions of Dollars)
Service Cost $ 8.3 $ 6.8 $ 6.5 $ 2.6 $ 2.5 $ 2.6
Interest Cost 25.9 23.5 22.0 9.4 7.8 7.8
Expected return on assets (59.3) (41.6) (35.5) N/A N/A N/A
Prior service cost amortization 1.1 1.1 1.4 0.7 0.7 0.7
Actuarial (gain) loss (9.6) (7.0) (5.2) 1.0 0.1 0.5
Transition amount amortization 0.8 0.8 0.8 19.1 18.9 9.5
Amounts contributed by (to)
Company affiliates 0.3 0.3 0.2 (0.7) (0.7) (0.6)
------ ------ ----- ----- ----- -----
Net periodic benefit cost $(32.5) $(16.1) $(9.8) $32.1 $29.3 $20.5
====== ====== ===== ===== ===== =====
Weighted-Average Assumptions as of December 31
Other
Retirement Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
Discount rate 7.0% 7.5% 7.5% 7.0% 7.5% 7.5%
Expected return on plan assets 9.5% 8.0% 8.0% NA NA NA
Rate of compensation increase 4.0% 4.0% 3.0% 4.0% 4.0% 3.0%
Change in Benefit Obligation
Other
Retirement Benefits Postretirement Benefits
1998 1997 1998 1997
(Millions of Dollars) (Millions of Dollars)
Benefit obligation, January 1 $344.4 $306.9 $108.8 $110.1
Service cost 8.3 6.8 2.6 2.5
Interest cost 25.9 23.5 9.4 7.8
Plan participants' contributions 0.1 0.2 0.5 0.5
Actuarial (gain)/loss 28.3 25.1 23.3 (5.2)
Benefits paid (17.7) (18.1) (7.6) (6.9)
------ ------ ------ ------
Benefit obligation, December 31 $389.3 $344.4 $137.0 $108.8
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
1998 1997
---- ----
(Millions of Dollars)
Fair value of plan assets, January 1 $632.9 $523.5
Actual return on plan assets 83.5 119.5
Company contribution - 7.8
Plan participants' contributions 0.1 0.2
Benefits paid (17.7) (18.1)
------ ------
Fair value of plan assets, December 31 $698.8 $632.9
====== ======
The Company does not fund postretirement benefits other than pensions.
Funded Status of Plans
Other
Retirement Benefits Postretirement Benefits
1998 1997 1998 1997
(Millions of Dollars) (Millions of Dollars)
Funded status, December 31 $309.5 $288.5 $(137.0) $(108.8)
Unrecognized actuarial (gain)/loss (213.4) (227.1) 34.5 12.2
Unrecognized prior service cost 12.3 13.4 5.1 5.8
Unrecognized net transition
obligation 6.5 7.4 10.7 29.8
------ ------ ------- -------
Net amount recognized in
Consolidated Balance Sheets $114.9 $ 82.2 $ (86.7) $ (61.0)
====== ====== ======== =======
Health Care Trends
The determination of net periodic postretirement benefit cost is based on the
following assumptions:
1998 1997 1996
- -------------------------------------------------------------------------------
Health care cost trend rate 8.5% 9.0% 9.5%
Ultimate health care cost trend rate 5.0% 5.5% 5.5%
Year achieved 2005 2004 2004
The effect of a one-percentage-point increase or decrease in the assumed health
care cost trend rates on the aggregate of the service and interest cost
components of net periodic postretirement health care benefit cost and the
accumulated postretirement benefit obligation for health care benefits are as
follows:
1% 1%
Increase Decrease
(Millions of Dollars)
Effect on health care cost $0.2 $(0.3)
Effect on postretirement obligation 3.5 (3.9)
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
For regulatory purposes, 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, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations. Such amounts are deferred and
amortized with recovery provided through rates. The Company has also recovered
portions of its environmental liabilities through settlements with various
insurance carriers. As of December 31, 1998, the Company has recovered all
amounts previously deferred for its electric operations. The Company expects to
recover all deferred amounts related to its gas operations by December 2002.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $21.3 million and $32.4 million at December 31, 1998 and
1997, respectively. The deferral includes the estimated costs to be associated
with the matters discussed in Note 10C.
M. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide emission
allowances are purchased and financed by Fuel Company under a contract which
requires the Company to reimburse Fuel Company for all costs and expenses
relating to the ownership and financing of fuel inventories and sulfur dioxide
emission allowances. Accordingly, such fuel inventories and emission allowances
and fuel-related assets and liabilities are included in the Company's
consolidated financial statements. (See Note 4.)
N. Temporary Cash Investments
The Company considers temporary cash investments having original
maturities of three months or less to be cash equivalents. Temporary cash
investments are generally in the form of commercial paper, certificates of
deposit and repurchase agreements.
P. Recently Issued Accounting Standard
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The provisions of the Statement, which will be implemented by the
Company for the fiscal year beginning January 1, 2000, establish accounting and
reporting standards for derivative instruments, including those imbedded in
other contracts, and hedging activities. The impact that adoption of the
provisions of the Statement will have on the Company's results of operations,
cash flows and financial position has not been determined.
Q. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the 1998 presentation.
R. Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
2. RATE MATTERS:
A. On December 11, 1998, the PSC issued an order requiring the Company to
reduce retail electric rates on a prospective basis. The PSC acted in response
to the Company reporting that it earned a 13.04 percent return on common equity
for its retail electric operations for the twelve months ended September 30,
1998. This return on common equity exceeded the Company's authorized return of
12 percent by 1.04 percent, or $22.7 million, primarily as a result of record
heat experienced during the summer. The order requires prospective rate
reductions on a per kilowatt-hour basis, based on actual retail sales for the
twelve months ended September 30, 1998. This action will reduce future reported
return on common equity to the Commission-authorized level if the Company
experiences the same weather effect and other business results as that of the
twelve months ended September 30, 1998. The order requires the rate reductions
to be placed into effect with the first billing cycle of January 1999. On
December 21, 1998, the Company filed a motion for reconsideration with the PSC.
On January 12, 1999, the PSC denied the Company's motion for reconsideration,
ruled that no further rate action was required, and reaffirmed the Company's
return on equity of 12 percent.
B. On January 9, 1996 the PSC issued an order granting the Company an
increase in retail electric rates of 7.34%, which was designed to produce
additional revenues, based on a test year, of approximately $67.5 million
annually. The increase was implemented in two phases. The first phase, an
increase in revenues of approximately $59.5 million annually, or 6.47%,
commenced in January 1996. The second phase, an increase in revenues of
approximately $8.0 million annually, or .87%, was implemented in January 1997.
The PSC authorized a return on common equity of 12.0%. The PSC also approved
establishment of a Storm Damage Reserve Account capped at $50 million to be
collected through rates over a ten-year period. Additionally, the PSC approved
accelerated recovery of a significant portion of the Company's electric
regulatory assets (excluding deferred income tax assets) and the remaining
transition obligation for postretirement benefits other than pensions, changing
the amortization periods to allow recovery by the end of the year 2000. The
Company's request to shift, for rate- making purposes, approximately $257
million of depreciation reserves from transmission and distribution assets to
nuclear production assets was also approved. The Consumer Advocate and two other
intervenors appealed certain issues in the order initially to the Circuit Court,
which affirmed the PSC's decisions, and, subsequently, to the Supreme Court. In
March 1998, the Company, the PSC, the Consumer Advocate and one of the other
intervenors reached an agreement that provided for the reversal of the shift in
depreciation reserves and the dismissal of the appeal of all other issues. The
PSC also authorized the Company to adjust depreciation rates that had been
approved in the 1996 rate order for its electric transmission, distribution and
nuclear production properties to eliminate the effect of the depreciation
reserve shift and to retroactively apply such depreciation rates to February
1996. As a result, a one-time reduction in depreciation expense of $5.5 million
after taxes was recorded in March 1998. The agreement does not affect retail
electric rates. The FERC had previously rejected the transfer of depreciation
reserves for rates subject to its jurisdiction. In September 1998, the Supreme
Court affirmed the Circuit Court's rulings on the issues contested by the
remaining intervenor.
C. In 1994 the PSC issued an order approving the Company's request to
recover through a billing surcharge to its gas customers the costs of
environmental cleanup at the sites of former manufactured gas plants. The
billing surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for the Company's gas operations that had
previously been deferred. In October 1998, as a result of the annual review, the
PSC approved the Company's request to maintain the billing surcharge at $.011
per therm which should enable the Company to recover the remaining balance of
$22.1 million by December 2002.
D. In September 1992 the PSC issued an order granting the Company a $.25
increase in transit fares from $.50 to $.75 in Columbia , South Carolina;
however, the PSC also required $.40 fares for low income customers and denied
the Company's request to reduce the number of routes and frequency of service.
The new rates were placed into effect in October 1992. The Company appealed the
PSC's order to the Circuit Court, which in May 1995 ordered the case back to the
PSC for reconsideration of several issues including the low income rider
program, routing changes, and the $.75 fare. The Supreme Court declined to
review an appeal of the Circuit Court decision and dismissed the case. The PSC
and other intervenors filed another Petition for Reconsideration, which the
Supreme Court denied. The PSC and other intervenors filed another appeal to the
Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In
this order, the Circuit Court upheld its previous orders and remanded them to
the PSC. During August 1996, the PSC heard oral arguments on the orders on
remand from the Circuit Court. On September 30, 1996, the PSC issued an order
affirming its previous orders and denied the Company's request for
reconsideration. The Company has appealed these two PSC orders to the Circuit
Court where they are awaiting action.
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including amounts due
under nuclear and fossil fuel agreements (see Note 4), and sinking fund
requirements for the years 1999 through 2003 are summarized as follows:
Year Amount Year Amount
(Millions of Dollars)
1999 $ 29.1 2002 $ 22.6
2000 188.6 2003 124.5
2001 22.6
--------------------------------------------------------------
Approximately $18.5 million of the portion of long-term debt payable in
1999 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.
On August 7, 1996 the City of Charleston executed 30-year electric and
gas franchise agreements with the Company. In consideration for the electric
franchise agreement, the Company is paying the City $25 million over seven years
(1996-2002) and has donated to the City the existing transit assets in
Charleston. The $25 million is included in electric plant-in-service. In
settlement of environmental claims the City may have had against the Company
involving the Calhoun Park area, where the Company and its predecessor companies
operated a manufactured gas plant until the 1960's, the Company is paying the
City $26 million over a four-year period (1996-1999). Such amount is deferred
(see Note 1L). The unpaid balances of these amounts are included in "Long-Term
Debt."
The Company has three-year revolving lines of credit totaling $75
million, in addition to other lines of credit, that provide liquidity for
issuance of commercial paper. The three-year lines of credit provide back-up
liquidity when commercial paper outstanding is in excess of $175 million. The
long-term nature of the lines of credit allow commercial paper in excess of $175
million to be classified as long-term debt. The Company had outstanding
commercial paper of $125.2 million and $13.3 million at December 31, 1998 and
1997, at weighted average interest rates of 5.32% and 5.90%, respectively.
Substantially all utility plant and fuel inventories are pledged as
collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories and sulfur dioxide emission
allowances are financed through the issuance by Fuel Company of short-term
commercial paper. These short-term borrowings are supported by an irrevocable
revolving credit agreement which expires December 19, 2000. Accordingly, the
amounts outstanding have been included in long-term debt. The credit agreement
provides for a maximum amount of $125 million that may be outstanding at any
time.
Commercial paper outstanding totaled $66.0 million and $80.3 million at
December 31, 1998 and 1997 at weighted average interest rates of 5.45% and
5.87%, respectively.
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including Preferred Stock Not
Subject to Purchase or Sinking Funds) during 1998, 1997 and 1996 are summarized
as follows:
Common Preferred Millions
Shares Shares of Dollars
Balance December 31, 1995 40,296,147 322,877 $1,341.1
Changes in Retained Earnings:
Net Income 190.5
Cash Dividends Declared:
Preferred Stock (at stated rates) (5.4)
Common Stock (135.8)
Equity Contributions from Parent
including transfer of assets 49.1
- --------------------------------------------------------------------------
Balance December 31, 1996 40,296,147 322,877 1,439.5
Changes in Retained Earnings:
Net Income 194.6
Cash Dividends Declared:
Preferred Stock (at stated rates) (9.3)
Common Stock (162.6)
Equity Contributions from Parent 12.1
Issuance of Preferred Stock 1,000,000 100.0
Redemption of Preferred Stock (197,668) (19.8)
Changes in Capital Stock Expense 0.1
Changes in Loss on Resale of
Reacquired Stock (1.6)
- --------------------------------------------------------------------------
Balance December 31, 1997 40,296,147 1,125,209 1,553.0
Changes in Retained Earnings:
Net Income 227.2
Cash Dividends Declared:
Preferred Stock (at stated rates) (7.5)
Common Stock (167.3)
Changes in Other Paid in Capital (0.2)
-------------------------------------------------------------------------
Balance December 31, 1998 40,296,147 1,125,209 $1,605.2
=========================================================================
The Restated Articles of Incorporation of the Company and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions that under
certain circumstances could limit the payment of cash dividends on common stock.
In addition, with respect to hydroelectric projects, the Federal Power Act
requires the appropriation of a portion of the earnings therefrom. At December
31, 1998 approximately $25.1 million of retained earnings were restricted by
this requirement as to payment of cash dividends on common stock.
6. PREFERRED STOCK:
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend. Retirements under sinking fund
requirements are at par values.
The aggregate annual amount of purchase fund or sinking fund requirements
for preferred stock for the years 1999 through 2003 is $2.8 million.
The changes in "Total Preferred Stock (Subject to Purchase or Sinking
Funds)" during 1998, 1997 and 1996 are summarized as follows:
Number Millions
of Shares of Dollars
Balance December 31, 1995 763,619 $ 48.7
Shares Redeemed:
$100 par value (7,198) (0.7)
$50 par value (50,319) (2.6)
- ---------------------------------------------------------------------------
Balance December 31, 1996 706,102 45.4
Shares Redeemed:
$100 par value (202,812) (20.3)
$50 par value (252,196) (12.6)
- ---------------------------------------------------------------------------
Balance December 31, 1997 251,094 12.5
Shares Redeemed:
$50 par value (11,042) (1.0)
- ---------------------------------------------------------------------------
Balance December 31, 1998 240,052 $ 11.5
===========================================================================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly-owned subsidiary of
the Company, issued $50 million (2,000,000 shares) of 7.55% Trust Preferred
Securities, Series A (the "Preferred Securities"). The Company owns all of the
Common Securities of the Trust (the "Common Securities"). The Preferred
Securities and the Common Securities (the "Trust Securities") represent
undivided beneficial ownership interests in the assets of the Trust. The Trust
exists for the sole purpose of issuing the Trust Securities and using the
proceeds thereof to purchase from the Company its 7.55% Junior Subordinated
Debentures due September 30, 2027. The sole asset of the Trust is $50 million of
Junior Subordinated Debentures of the Company. Accordingly, no financial
statements of the Trust are presented. The Company's obligations under the
Guarantee Agreement entered into in connection with the Preferred Securities,
when taken together with the Company's obligation to make interest and other
payments on the Junior Subordinated Debentures issued to the Trust and the
Company's obligations under its Indenture pursuant to which the Junior
Subordinated Debentures are issued, provides a full and unconditional guarantee
by the Company of the Trust's obligations under the Preferred Securities.
Proceeds were used to redeem preferred stock of the Company.
The preferred securities of the Trust are redeemable only in conjunction
with the redemption of the related 7.55% Junior Subordinated Debentures. The
Junior Subordinated Debentures will mature on September 30, 2027 and may be
redeemed, in whole or in part, at any time on or after September 30, 2002 or
upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received
from counsel experienced in such matters that there is more than an
insubstantial risk that: (1) the Trust is or will be subject to Federal income
tax, with respect to income received or accrued on the Junior Subordinated
Debentures, (2) interest payable by the Company on the Junior Subordinated
Debentures will not be deductible, in whole or in part, by the Company for
Federal income tax purposes, and (3) the Trust will be subject to more than a de
minimis amount of other taxes, duties, or other governmental charges.
Upon the redemption of the Junior Subordinated Debentures, payment will
simultaneously be applied to redeem Preferred Securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Subordinated Debentures. The Preferred Securities are redeemable at $25 per
preferred security plus accrued distributions.
7. INCOME TAXES:
Total income tax expense for 1998, 1997 and 1996 is as follows:
1998 1997 1996
- ----------------------------------------------------------------------------
(Millions of Dollars)
Current taxes:
Federal $116.1 $ 88.0 $ 88.2
State 2.1 (6.9) 13.1
- ----------------------------------------------------------------------------
Total current taxes 118.2 81.1 101.3
- ----------------------------------------------------------------------------
Deferred taxes, net:
Federal 1.8 3.7 8.3
State 2.0 1.5 1.8
- -----------------------------------------------------------------------------
Total deferred taxes 3.8 5.2 10.1
- -----------------------------------------------------------------------------
Investment tax credits:
Deferred - State 14.3 19.0 -
Amortization of amounts
deferred-State (0.9) (1.5) -
Amortization of amounts
deferred-Federal (3.2) (3.2) (3.2)
- ----------------------------------------------------------------------------
Total Investment Tax credit 10.2 14.3 (3.2)
- ----------------------------------------------------------------------------
Total income tax expense $132.2 $100.6 $108.2
============================================================================
The difference in total income tax expense and the amount calculated from
the application of the statutory Federal income tax rate (35% for 1998, 1997 and
1996) to pre-tax income is reconciled as follows:
1998 1997 1996
- ---------------------------------------------------------------------------
(Millions of Dollars)
Net income $227.2 $194.7 $190.5
Total income tax expense:
Charged to operating expenses 128.0 98.1 107.7
Charged (credited) to other items 4.2 2.5 0.5
- ---------------------------------------------------------------------------
Total pre-tax income $359.3 $295.3 $298.7
==========================================================================
Income taxes on above at statutory
Federal income tax rate $125.8 $103.4 $104.5
Increases (decreases) attributable to:
State income taxes (less Federal
income tax effect) 11.4 7.9 9.7
Deferred income tax reversal at
higher than statutory rates (3.0) (3.5) (3.4)
Amortization of Federal
investment tax credits (3.2) (3.2) (3.2)
Allowance for equity funds
used during construction (2.4) (2.1) (1.4)
Other differences, net 3.6 (1.9) 2.0
- --------------------------------------------------------------------------
Total income tax expense $132.2 $100.6 $108.2
==========================================================================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability at December 31, 1998 and 1997 are as
follows:
1998 1997
- ----------------------------------------------------------------------------
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 61.7 $ 55.4
Cycle billing 20.6 20.5
Early retirement programs 13.0 3.1
Deferred compensation 7.2 6.7
Other postretirement benefits 32.9 14.6
Other 12.0 8.1
- ----------------------------------------------------------------------------
Total deferred tax assets 147.4 108.4
- ----------------------------------------------------------------------------
Deferred tax liabilities:
Property plant and equipment 584.9 561.2
Pension expense 39.2 27.5
Reacquired debt 7.5 7.5
Research and experimentation 32.5 19.5
Deferred fuel 3.4 3.6
Other 8.1 7.6
- ----------------------------------------------------------------------------
Total deferred tax liabilities 675.6 626.9
- ----------------------------------------------------------------------------
Net deferred tax liability $528.2 $518.5
============================================================================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of SCANA Corporation through 1989, and has examined and
proposed adjustments to SCANA's Federal returns for 1990 through 1995. The
Company does not anticipate that any adjustments which might result from these
examinations will have a significant impact on the results of operations, cash
flows or financial position of the Company.
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1998 and 1997 are as follows:
1998 1997
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Millions of Dollars)
Assets:
Cash and temporary cash
investments $ 35.6 $ 35.6 $ 6.0 $ 6.0
Investments 5.1 5.1 5.3 5.3
Liabilities:
Short-term borrowings 125.2 125.2 13.3 13.3
Long-term debt 1,234.8 1,356.4 1,309.5 1,384.7
Preferred stock (subject
to purchase or sinking funds) 12.0 11.3 12.5 11.3
The information presented herein is based on pertinent information available to
the Company as of December 31, 1998 and 1997. 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, 1998, 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:
o Cash and temporary cash investments, including commercial paper,
repurchase agreements, treasury bills and notes, are valued at their
carrying amount.
o Fair values of investments and long-term debt are based on quoted market
prices of the instruments or similar instruments, or for those
instruments for which there are no quoted market prices available, fair
values are based on net present value calculations. Investments which are
not considered to be financial instruments 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.
o Short-term borrowings are valued at their carrying amount.
o The fair value of preferred stock (subject to purchase or sinking funds)
is estimated on the basis of market prices.
o 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 committed lines of
credit. Commercial paper borrowings are for 270 days or less. Details of lines
of credit (including uncommitted lines of credit) and short-term borrowings,
excluding amounts classified as long-term (Notes 3 and 4), at December 31, 1998
and 1997 and for the years then ended are as follows:
1998 1997
(Millions of dollars)
Authorized lines of credit at year-end $285 $315
Unused lines of credit at year-end $285 $315
Short-term borrowings outstanding at year-end:
Commercial paper $125.2 $13.3
Weighted average interest rate 5.32% 5.90%
- --------------------------------------------------------------------------
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
SCANA and Westvaco, each own a 50% interest in Cogen South LLC (Cogen).
Cogen was formed to build and operate a cogeneration facility at Westvaco's
Kraft Division Paper Mill in North Charleston, South Carolina. Construction of
the facility began in September 1996 and is in the final stages. Construction
financing of approximately $170 million was provided to Cogen by banks. On
September 10, 1998, the contractor in charge of construction filed suit in
Circuit Court seeking approximately $51 million from Cogen, alleging that
construction cost overruns relating to the facility were incurred and that the
construction contract provides for recovery of these costs. In addition to
Cogen, Westvaco, the Company and SCANA were also named in the suit. The Company
and the other defendants believe the suit is without merit and are mounting an
appropriate defense. The Company does not believe that the resolution of this
issue will have a material impact on its results of operations, cash flows or
financial position.
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 $9.7 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 million of the liability per reactor would be
assessed per year. The Company's maximum assessment, based on its two-thirds
ownership of Summer Station, would be approximately $58.7 million per incident,
but not more than $6.7 million per year.
The Company currently maintains policies (for itself and on behalf of
Santee Cooper) with Nuclear Electric Insurance Limited (NEIL) and American
Nuclear Insurers (ANI) providing combined property and decontamination insurance
coverage of $2.0 billion for any losses at Summer Station. The Company pays
annual premiums and, in addition, could be assessed a retroactive premium not to
exceed five times its annual premium in the event of property damage loss to any
nuclear generating facilities covered under the NEIL program. Based on the
current annual premium, this retroactive premium would not exceed $6.1 million.
To the extent that insurable claims for property damage, decontamination,
repair and replacement and other costs and expenses arising from a nuclear
incident at Summer Station exceed the policy limits of insurance, or to the
extent such insurance becomes unavailable in the future, and to the extent that
the Company's rates would not recover the cost of any purchased replacement
power, the Company will retain the risk of loss as a self-insurer. The Company
has no reason to anticipate a serious nuclear incident at Summer Station. If
such an incident were to occur, it could have a material adverse impact on the
Company's results of operations, cash flows and financial position.
C. Environmental
In September 1992, the EPA notified the Company, the City of Charleston
and the Charleston Housing Authority of their potential liability for the
investigation and cleanup of the Calhoun Park area site in Charleston, South
Carolina. This site encompasses approximately 30 acres and includes properties
which were locations for industrial operations, including a wood preserving
(creosote) plant, one of the Company's decommissioned manufactured gas plants,
properties owned by the National Park Service and the City of Charleston, and
private properties. The site has not been placed on the National Priorities
List, but may be added in the future. The PRPs have negotiated an administrative
order by consent for the conduct of a Remedial Investigation/Feasibility Study
and a corresponding Scope of Work. Field work began in November 1993, and the
EPA approved a Remedial Investigation Report in February 1997 and a Feasibility
Study Report in June 1998. In July 1998, the EPA approved the Company's Removal
Action Work Plan for soil excavation. The Company completed Phase One of the
Removal Action in 1998 at a cost of approximately $1.5 million. Phase Two will
include excavation and installation of several permanent barriers to mitigate
coal tar seepage. Phase Two began in November 1998, and is expected to cost
approximately $2.2 million. On September 30, 1998 a Record of Decision, was
issued which sets forth EPA's view of the extent of each PRP's responsibility
for site contamination and the level to which the site must be remediated. On
January 13, 1999 the EPA issued a Unilateral Administrative Order for Remedial
Design and Remedial Action directing the Company to design and carry out a plan
of remediation for the Calhoun Park site. The Order is temporarily stayed
pending further negotiations between the Company and the EPA.
In October 1996 the City of Charleston and the Company settled all
environmental claims the City may have had against SCE&G involving the Calhoun
Park area for a payment of $26 million over four years (1996-1999) by SCE&G to
the City. The Company is recovering the amount of the settlement, which does not
encompass site assessment and cleanup costs, through rates in the same manner as
other amounts accrued for site assessments and cleanup as discussed above. As
part of the environmental settlement, SCE&G has agreed to construct an 1,100
space parking garage on the Calhoun Park site and to transfer the facility to
the City in exchange for a 20-year municipal bond backed by revenues from the
parking garage and a mortgage on the parking garage. The total amount of the
bond is not to exceed $16.9 million, the maximum expected project cost. The
parking garage is currently under construction, and is scheduled for completion
in the spring of the year 2000.
The Company owns three other decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. For the site located in
Sumter, South Carolina, effective September 15, 1998, the Company entered into a
Remedial Action Plan Contract with South Carolina Department of Health and
Environmental Control (DHEC) pursuant to which it agreed to undertake a full
site investigation and remediation under the oversight of DHEC. Site
investigation and characterization are proceeding according to schedule. Upon
selection and successful implementation of a site remedy, DHEC will give the
Company a Certificate of Completion, and a covenant not to sue. The Company is
continuing to investigate the other two sites, and is monitoring the nature and
extent of residual contamination.
D. Franchise Agreements
See Note 3 for a discussion of the electric franchise agreement between
the Company and the City of Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation incidental to its
business operations which management anticipates will be resolved without
material loss to the Company. No estimate of the range of loss from these
matters can currently be determined.
11. SEGMENT OF BUSINESS INFORMATION:
The Company's reportable segments, based on combined revenues from
external and internal sources, are Electric Operations and Gas Distribution.
Electric Operations is comprised of the electric portion of the Company and Fuel
Company. This segment is primarily engaged in the generation, transmission, and
distribution of electricity. The Company's electric service territory extends
into 24 counties covering more than 15,000 square miles in the central,
southern, and southwestern portions of South Carolina. Sales of electricity to
industrial, commercial, and residential customers are regulated by the PSC. Fuel
Company acquires, owns, and provides financing for the fuel and emission
allowances required for the operation of SCE&G's generation facilities.
Gas Distribution is comprised of the Company's local distribution
operations. This segment is engaged in the purchase and sale, primarily at
retail, of natural gas. These operations extend to 30 counties in South Carolina
covering approximately 21,000 square miles.
The accounting policies of the segments are the same as those described
in the summary of significant accounting policies. The Company records
intersegment sales and transfers of electricity and gas based on rates
established by the appropriate regulatory authority. Non-regulated sales and
transfers are recorded at current market prices.
The Company's reportable segments share a similar regulatory
environment and, in some cases, an overlapping service area. However, Electric
Operation's product differs from Gas Distribution, as does its generation
process and method of distribution.
Disclosure of Reportable Segments
(Millions of Dollars)
- --------------------------------------------------------------------------------
Electric Gas All
1998 Operations1 Distribution Other2 Total
- --------------------------------------------------------------------------------
External Customer Revenue 1,220 230 1 1,451
Revenue from Affiliates 201 3 - 204
Operating Income (Loss) 307 21 (5) 323
Depreciation and Amortization 120 11 - 131
Segment Assets 4,305 381 209 4,895
Expenditures for Assets 179 19 39 237
- -------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Electric Gas All
1997 Operations1 Distribution Other2 Total
- --------------------------------------------------------------------------------
External Customer Revenue 1,103 234 2 1,338
Revenue from Affiliates 24 1 - 25
Operating Income (Loss) 269 22 (4) 287
Depreciation and Amortization 129 11 - 140
Segment Assets 4,240 364 227 4,831
Expenditures for Assets 186 15 32 233
- -----------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Electric Gas All
1996 Operations1 Distribution Other2 Total
- --------------------------------------------------------------------------------
External Customer Revenue 1,107 235 3 1,345
Revenue from Affiliates 23 1 - 24
Operating Income (Loss) 278 19 (7) 290
Depreciation and Amortization 123 12 - 135
Segment Assets 4,073 350 158 4,581
Expenditures for Assets 183 19 25 226
Significant non-cash activities 21 20 - 41
- ----------------------------------------------------------------------
1Management uses operating income and utility plant to measure segment
profitability and financial position, respectively. Accordingly, the Company
does not allocate interest charges, income tax/(benefit), accumulated
depreciation, common and non-utility plant, or deferred tax assets to its
segments. Interest income is not reported by segment and is not material.
2Revenues and assets from segments below the quantitative thresholds
are attributable primarily to the Company's transit operations, SCE&G Trust I
and non-regulated activities. None of these segments met any of the quantitative
thresholds for determining reportable segments in 1998, 1997 or 1996.
Significant non-cash activities included the Charleston electric franchise
agreement and the Charleston environmental agreement related to a manufactured
gas plant site.
Reconciliation of Reportable Segments
to Consolidated Financial Statements
(Millions of Dollars)
--------------------------------------------------------------------------
Total Operating
1998 Revenue Income/(Loss) Assets
--------------------------------------------------------------------------
Reportable Segments 1,653 328 4,686
All Other 2 (5) 209
Unallocated - - (469)
Elimination of Affiliates (204) (11) (65)
Adjustments - - (115)
-------------------------------------------------------------------
Consolidated Totals 1,451 312 4,246
--------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Operating
1997 Revenue Income/(Loss) Assets
---------------------------------------------------------------------------
Reportable Segments $ 1,362 $ 291 $ 4,603
All Other 2 (4) 227
Unallocated - - (631)
Elimination of Affiliates (26) (5) (65)
Adjustments - - (80)
-------------------------------------------------------------------------
Consolidated Totals $ 1,338 $ 282 $ 4,054
-------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Operating
1996 Revenue Income/(Loss) Assets
---------------------------------------------------------------------------
Reportable Segments $ 1,366 $ 297 $ 4,423
All Other 3 (7) 158
Unallocated - - (547)
Elimination of Affiliates (24) (4) (12)
Adjustments - - (63)
-------------------------------------------------------------------------
Consolidated Totals $ 1,345 $ 286 $ 3,959
-------------------------------------------------------------------------
The Consolidated Financial Statements report operating revenues,
comprised of the reportable segments and the non-reportable transit operations
segment. Adjustments to assets consist of various reclassifications made for
external reporting purposes. Unallocated net income consists of the Company's
net income. Segment assets include utility plant only (excluding accumulated
depreciation) for all segments. As a result, unallocated assets include
accumulated depreciation, offset in part by common and non-utility plant and
non-fixed assets for the segments.
Reconciliation of Other Significant Items
(Millions of Dollars)
---------------------------------------------------------------------------
Consolidated
Segment Totals Adjustments Totals
1998
Depreciation and Amortization 131 - 131
Expenditures for Assets 237 8 245
1997
Depreciation and Amortization 140 - 140
Expenditures for Assets 233 (1) 232
1996
Depreciation and Amortization 135 - 135
Expenditures for Assets 227 (18) 209
Significant Non-cash Activities 41 - 41
---------------------------------------------------------------------------
Expenditures for Assets in 1996 are adjusted primarily to remove the
non-cash transaction related to the Charleston Franchise Agreement.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1998
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
(Millions of Dollars)
Total operating
revenues $358 $343 $431 $320 $1,452
Operating income 83 67 112 51 313
Net income 60 44 88 35 227
- ----------------------------------------------------------------------------
1997
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
(Millions of Dollars)
Total operating
revenues $337 $289 $377 $335 $1,338
Operating income 74 52 93 63 282
Net income 50 30 73 42 195
- ----------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
SCANA:
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 SCANA Corporation" on page 21 herein. The other
information required by Item 10 is incorporated herein by reference to the
captions "Election of Directors - Proposals 1 and 2" and "Other Information
Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive
proxy statement for the 1999 annual meeting of shareholders which will be filed
with the SEC pursuant to Regulation 14A, promulgated under the Securities
Exchange Act of 1934.
SCE&G:
DIRECTORS
The directors listed below were elected April 23, 1998 to hold office
until the next annual meeting of SCE&G's stockholders on April 22, 1999.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 55 For more than five years, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).
For more than five years, Chairman and Chief
Executive Officer of Amick Processing, Inc.
and Amick Broilers, Inc.
Director, Blue Cross and Blue Shield of South
Carolina, Columbia, SC; SCANA Corporation,
Columbia, SC.
James A. Bennett 38 Since December 1998, Senior Vice President and
(1997) Director of Professional Banking, First
Citizens Bank, Columbia, SC.
From December 1994 to December 1998, Senior
Vice President and Director of Community
Banking, First Citizens Bank, Columbia, SC.
From March 1991 to December 1994,President
of Victory Savings Bank, Columbia, SC.
Director, SCANA Corporation
William B. Bookhart, Jr. 57 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 69 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC;
Member, Advisory Board of Liberty Mutual
Insurance Group.
Name and Year First
Became Director Age Principal Occupation; Directorships
Hugh M. Chapman 66 Since June 30, 1997, retired from NationsBank
(1988) South, Atlanta, GA (a division of
NationsBank Corporation, bank holding
company).
For more than five years prior to June
30,1997, Chairman of NationsBank South,
Atlanta, GA
Director, SCANA Corporation, Columbia, SC;
West Point-Stevens, Inc and PrintPak, Inc.
Elaine T. Freeman 63 For more than five years, Executive Director (1992) of ETV
Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg, SC.
Director, National Bank of South Carolina,
Columbia, SC; SCANA Corporation,
Columbia, SC.
Lawrence M. Gressette, Jr. 67 Since February 28, 1997, Chairman Emeritus
(1987) of SCANA Corporation.
For more than five years prior to February
28, 1997, Chairman of the Board and Chief
Executive Officer of SCANA Corporation all
SCANA subsidiaries.
Director, Wachovia Corporation, Winston-
Salem, NC; SCANA Corporation, Columbia,
SC.
W. Hayne Hipp 59 For more than five years, Chairman, President
(1983) and Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance and
broadcasting holding company).
Director, The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC; SCANA Corporation,
Columbia, SC.
F. Creighton McMaster 69 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor of
petroleum products).
Director, First Union National Bank South
Carolina, Greenville, SC; SCANA Corporation,
Columbia, SC.
Name and Year First
Became Director Age Principal Occupation; Directorships
Lynne M. Miller 47 Since February, 1998, Chief Executive
(1997) Officer of Environmental Strategies
Corporation, Reston, VA (environmental
consulting and engineering firm).
For more than five years prior to February
1998,President of Environmental Strategies
Corporation, Reston, VA.
Director, SCANA Corporation, Columbia, SC.
John B. Rhodes 68 For more than five years, Chairman and
(1967) Chief Executive Officer, Rhodes Oil
Company, Inc., Walterboro, SC (distributor
of petroleum products).
Director, SCANA Corporation, Columbia, SC.
Maceo K. Sloan 49 For more than five years, Chairman, President
(1997) and CEO of Sloan Financial Group, Inc. and
Chairman, President and CEO of NCM Capital
Management Group, Inc, both of which are
located in Durham, NC.
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 52 Since March 1, 1997, Chairman and Chief
(1991) Executive Officer of SCANA Corporation.
From August 21, 1996 to March 1, 1997, Chief
Operating Officer of SCANA Corporation.
Since December 13, 1995, President of SCANA
Corporation.
From May 1, 1994 to December 13, 1995,
Executive Vice President, Chief Financial
Officer and Controller of SCANA Corporation.
For more than five years prior to May 1,
1994, Senior Vice President, Chief
Financial Officer and Controller of SCANA
Corporation.
Director, SCANA Corporation, Columbia, SC;
Powertel, Inc., West Point, GA, ITC^DeltaCom,
West Point, GA; and The Liberty Corporation,
Greenville, SC.
117
EXECUTIVE OFFICERS OF SCE&G
SCE&G's officers are elected at the annual organizational meeting of the
Board of Directors and hold office until the next such organizational meeting,
unless the Board of Directors shall otherwise determine, or unless a resignation
is submitted.
Positions Held During
Name Age Past Five Years Dates
W. B. Timmerman 52 Chairman of the Board and
Chief Executive Officer 1997-present
Chief Operating Officer
of SCANA 1996-1997
President of SCANA 1995-present
President of SCANA
Communications, Inc.,
an affiliate 1996-1997
Executive Vice President, *-1995
Chief Financial Officer,
and Controller 1994-1996
Senior Vice President,
Chief Financial Officer
and Controller, *-1994
J. L. Skolds 48 Group Executive - SCANA
Electric Group 1997-present
President and Chief
Operating Officer,
SCE&G 1996-present
Senior Vice President -
Generation, SCE&G 1994-1996
Vice President - Nuclear
Operations, SCE&G *-1994
G. J. Bullwinkel, Jr. 50 President of SCANA
Communications, Inc. 1997-present
Senior Vice President-
Retail Electric, SCE&G 1995-present
Senior Vice President-
Fossil & Hydro Production *-1994
W. A. Darby 53 Senior Vice President -
Gas, SCANA Gas Group 1996-present
Vice President-Gas Operations *-1996
President and Treasurer of
ServiceCare, Inc. an
affiliate 1996-present
General Manager of ServiceCare,
Inc., an affiliate 1994-1996
K. B. Marsh 43 Senior Vice President - Finance
Chief Financial Officer and
Controller - SCANA 1998-present
Vice President - Finance,
Chief Financial Officer
and Controller - SCANA 1996-1998
Vice President - Finance,
Treasurer and Secretary,
SCANA *-1996
Vice President 1996-present
*Indicates position held at least since March 1, 1994
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of SCE&G's common stock is held by its parent, SCANA Corporation.
The required forms indicate that no equity securities of SCE&G are owned by its
directors and executive officers. Based solely on a review of the copies of such
forms and amendments furnished to SCE&G and written representations from the
executive officers and directors, SCE&G believes that during 1998 all Section
16(a) filing requirements applicable to its executive officers, directors and
greater than 10% beneficial owners were complied with.
ITEM 11. EXECUTIVE COMPENSATION
SCANA:
The information called for by Item 11, "Executive Compensation", is
incorporated herein by reference to the captions "Director Compensation" and
"Compensation Committee Interlocks and Insider Participation," and "Executive
Compensation" in SCANA's definitive proxy statement for the 1999 annual meeting
of shareholders.
SCE&G:
The following table contains information with respect to compensation
paid or accrued during the years 1998, 1997 and 1996 to the Chief Executive
Officer of SCE&G and to each of the other four most highly compensated executive
officers of SCE&G during 1998.
SUMMARY COMPENSATION TABLE
Name and Principal Year Annual Compensation Long-Term
Position Compensation
(1) (2) (3) (4) (5)
Salary Bonus Other Payouts All Other
($) ($) Annual LTIP Compensation
Compensation Payouts ($)
($) ($)
W. B. Timmerman
Chairman, President, 1998 455,909 303,780 17,514 - 27,138
Chief Executive 1997 400,634 318,815 12,220 88,338 24,038
Officer and Director 1996 335,266 196,832 6,399 109,819 20,116
- - SCANA Corporation
J. L. Skolds
SCANA Group Executive 1998 305,123 163,399 14,099 - 18,201
Electric Group; 1997 277,132 161,677 5,777 70,283 16,628
President and Chief 1996 215,708 114,099 2,453 55,513 12,943
Operating Officer - SCE&G
G. J. Bullwinkel 1998 229,152 99,372 11,726 - 13,706
Senior Vice President 1997 219,273 92,796 7,776 70,283 13,156
- - Retail Electric - SCE&G 1996 205,980 90,370 3,710 66,374 12,359
K. B. Marsh 1998 219,860 99,372 8,654 - 13,122
Senior Vice President, 1997 199,845 104,276 2,945 44,491 11,991
Chief Financial Officer 1996 166,616 75,667 1,189 46,462 9,997
and Controller - SCANA
W. A. Darby 1998 179,923 62,213 7,961 - 10,276
Senior Vice President, 1997 169,606 73,800 7,025 44,491 10,176
Gas, SCANA Gas Group 1996 157,659 54,090 3,566 46,462 9,460
President of ServiceCare
- ----------------
(1) Payments under SCANA's Annual Incentive Plan.
(2) For 1998, other annual compensation consists of automobile allowance, life
insurance premiums on policies owned by named executive officers and payments to
cover taxes on benefits of $4,500, $7,435 and $5,579 for Mr. Timmerman; $6,000,
$6,878 and $1,221 for Mr. Skolds; $6,000, $4,993 and $733 for Mr. Bullwinkel;
$6,905, $1,183 and $566 for Mr. Marsh; and $2,748, $4,340 and $873 for Mr.
Darby. (3) Payments under the SCANA's Performance Share Plan. (4) All other
compensation for all named executive officers consists solely of SCANA's
contributions to defined contribution plans. (5) Reflects actual salary paid in
1998. Base salary of $472,000 became
effective on May 1, 1998.
The following table shows the target awards made in 1998, (for potential
payment in 2000) under the Performance Share Plan and estimated future payouts
under that plan at threshold, target and maximum levels for each of the
executive officers included in the Summary Compensation Table.
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1998 TO BE PAID IN 2001
Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation
Name Rights (#) or Payout Threshold Target Maximum
($ or #) ($ or #) ($ or #)
W. B. Timmerman 10,230 1998-2000 4,092 10,230 15,345
J. L. Skolds 5,160 1998-2000 2,064 5,160 7,740
G. J. Bullwinkel 2,790 1998-2000 1,116 3,990 4,185
K. B. Marsh 2,790 1998-2000 1,116 2,790 4,185
W. A. Darby 2,000 1998-2000 800 2,000 3,000
Payouts occur when SCANA's Total Shareholder Return is in the top
two-thirds of the Performance Share Plan peer group, and will vary based on
SCANA's ranking against the peer group. Executives earn threshold payouts at the
33rd percentile of three-year performance. Target payouts will be made at the
50th percentile of three-year performance. Maximum payouts will be made when
Performance is at or above the 75th percentile of the peer group. Payments will
be made on a sliding scale for performance between threshold and target and
target and maximum. No payouts will be earned if performance is at less than the
33rd percentile. Awards are designated as target shares of SCANA Common Stock
and may be paid in stock or cash or a combination of stock and cash.
DEFINED BENEFIT PLANS
In addition to its Retirement Plan for all employees, SCANA has
Supplemental Executive Retirement Plans ("SERPs") for certain eligible
employees, including officers. A SERP is an unfunded plan which provides for
benefit payments in addition to those payable under a qualified retirement plan.
It maintains uniform application of the Retirement Plan benefit formula and
would provide, among other benefits, payment of Retirement Plan formula pension
benefits, if any, which exceed those payable under the Internal Revenue Code
maximum benefit limitations.
The following table illustrates the estimated maximum annual benefits
payable upon retirement at normal retirement date under SCANA's
Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$150,000 $ 41,777 $ 55,702 $ 69,628 $ 83,553 $ 86,229
200,000 56,777 75,702 94,628 113,553 117,479
250,000 71,777 95,702 119,628 143,553 148,729
300,000 86,777 115,702 144,628 173,553 179,979
350,000 101,777 135,702 169,628 203,553 211,229
400,000 116,777 155,702 194,628 233,553 242,479
450,000 131,777 175,702 219,628 263,553 273,729
500,000 146,777 195,702 244,628 293,553 304,979
550,000 161,777 215,702 269,628 323,553 336,229
600,000 176,777 235,702 294,628 353,553 367,479
650,000 191,777 255,702 319,628 383,553 398,729
700,000 206,777 275,702 344,628 413,553 429,979
750,000 221,777 295,702 369,628 443,553 461,229
800,000 236,777 315,702 394,628 473,553 492,479
850,000 251,777 335,702 419,628 503,553 523,729
900,000 266,777 355,702 444,628 533,553 554,979
950,000 281,777 375,702 469,628 563,553 586,229
1,000,000 296,777 395,702 494,628 593,553 617,479
For all the executive officers included in the Summary Compensation
Table for 1998, compensation shown in the column labeled "Salary" of the Summary
Compensation Table is covered by the Retirement Plan or a SERP. As of December
31, 1998, Mr. Timmerman had credited service under the Retirement Plan (or its
equivalent under the SERP) of 20 years; Mr. Skolds of 12 years; Mr. Bullwinkel
of 27 years; Mr. Marsh of 14 years; and Mr. Darby of 30 years. Benefits are
computed based on a straight-life annuity with an unreduced 60% surviving spouse
benefit. The amounts in this table assume continuation of the primary Social
Security benefits in effect at January 1, 1999 and are not subject to any
deduction for Social Security or other offset amounts.
The Company also has a Key Employee Retention Plan covering officers
and certain other executive employees, that provides supplemental retirement or
death benefits for participants. Under the plan, each participant may elect to
receive either (i) a monthly retirement benefit for 180 months upon retirement
at or after the earlier of the attainment of age 65, or completion of 35 years
of service with the Company, equal to 25% of the average monthly salary of the
participant over his final 36 months of employment prior to such retirement, or
(ii) an optional death benefit payable monthly to a participant's designated
beneficiary for 180 months, in an amount equal to 35% of the average monthly
salary of the participant over his final 36 months of employment prior to such
retirement. In the event of the participant's death prior to such retirement,
SCANA will pay to the participant's designated beneficiary for 180 months, a
monthly benefit equal to 50% of the participant's base monthly salary in effect
at death.
All of the executive officers named in the Summary Compensation Table
are participating in the plan. The estimated annual retirement benefits payable
at age 65, under the Key Employee Retention Plan based on projected eligible
compensation (assuming increases of 4% per year) to the executive officers named
in the Summary Compensation Table are as follows: Mr. Timmerman-$181,746; Mr.
Skolds-$140,995; Mr. Bullwinkel-$96,772; Mr. Marsh-$123,310 and Mr.
Darby-$67,755.
TERMINATION, SEVERANCE AND CHANGE IN CONTROL ARRANGEMENTS
SCANA maintains an Executive Benefit Plan Trust. The purpose of the
Trust is to help retain and attract quality leadership in key SCANA positions in
the current transitional environment of the utilities industry. The Trust is
used to receive SCANA contributions which may be used to pay the deferred
compensation benefits of certain directors, executives and other key employees
of SCANA in the event of a Change in Control (as defined in the Trust). All the
executive officers included in the Summary Compensation Table participate in
some of the plans listed below (the "Plans") which are covered by the Trust
including, in all cases, the Plans listed at (7) and (8).
(1) SCANA Corporation Voluntary Deferral Plan
(2) SCANA Corporation Supplementary Voluntary Deferral Plan
(3) SCANA Corporation Key Employee Retention Plan
(4) SCANA Corporation Supplemental Executive Retirement Plan
(5) SCANA Corporation Performance Share Plan
(6) SCANA Corporation Annual Incentive Plan
(7) SCANA Corporation Key Executive Severance Benefits Plan
(8) SCANA Corporation Supplementary Key Executive Severance
Benefits Plan
The Trust and the Plans provide flexibility to SCANA in responding to a
Potential Change in Control (as defined in the Trust) depending upon whether the
Change in Control would be viewed as being "hostile" or "friendly". This
flexibility includes the ability to deposit and withdraw SCANA contributions up
to the point of a Change in Control, and to affect the number of plan
participants who may be eligible for benefit distributions upon, or following, a
Change in Control.
The Key Executive Severance Benefits Plan is operative as a "single
trigger" plan, meaning that upon the occurrence of a "hostile" Change in
Control, benefits provided under Plans (1) through (6) above would be
distributed in a lump sum.
In contrast, the Supplementary Key Executive Severance Benefits Plan is
operative for a period of 24 months following a Change in Control which prior to
its occurrence is viewed as being "friendly." In this circumstance, the Key
Executive Severance Benefits Plan is inoperative. The Supplementary Key
Executive Severance Benefits Plan is a "double trigger" plan that would pay
benefits in lieu of those otherwise provided under plans (1) through (6) in
either of two circumstances: (a) the participant's involuntary termination of
employment without "Just Cause", or (b) the participant's voluntary termination
of employment for "Good Reason" (as these terms are defined in the Supplementary
Key Executive Benefits Plan).
Benefit distributions relative to a Change in Control, as to which
either the Key Executive Severance Benefits Plan or the Supplementary Key
Executive Severance Benefits Plan is operative, will be grossed up to include
estimated federal, state and local income taxes and any applicable excise taxes
owed by plan participants on those benefits.
The benefit distributions under the Key Executive Severance Benefits
Plans would include the following:
o An amount equal to three times the sum of: (1) the officer's annual base
salary in effect as of the Change in Control and (2) the larger of (i)
the officer's target award in effect as of the Change in Control under
the Annual Incentive Plan or (ii) the officer's average of actual annual
incentive bonuses received during the prior three years under the Annual
Incentive Plan.
o An amount equal to the projected cost for coverage for three full years
following the Change in Control as though the officer had continued to
be a SCANA employee with respect to medical coverage, long-term
disability coverage and either Life Plus (a special life insurance
program combining whole life and term coverages) or group term life
coverage, in accordance with the officer's actual election, in each case
so as to provide substantially the same level of coverage and benefits
as the officer enjoyed as of the date of the Change in Control.
o A benefit distribution under the Voluntary Deferral Plan calculated as
of the date of the Change in Control including implied interest through
such date, and a benefit under the Supplementary Voluntary Deferral Plan
calculated to include any implied dividends accrued under the plan
through the date of the Change in Control.
o A benefit distribution under the Key Employee Retention Plan calculated
as of the date of the Change in Control to include projected increases
to each participant's base salary applying cost of living increases and
as though the participant had reached the earlier of age 65 or completed
35 years of service.
o A benefit distribution under the Supplemental Executive Retirement Plan
calculated as an actuarial equivalent through the date of the Change in
Control with three additional years of compensation at the participant's
rate then in effect as though the participant had attained age 65 and
completed 35 years of benefit service and without any early retirement
or other actuarial reductions, which benefit would then be reduced by
the actuarial equivalent of the participant's qualified plan benefit
amount under the Retirement Plan.
o A benefit distribution under the Performance Share Plan equal to 100% of
the targeted awards for all performance periods which are not yet
completed as of the date of the Change in Control.
o A benefit distribution under the Annual Incentive Plan equal to 100% of
the target award in effect as of the date of the Change in Control.
Benefits under the Supplementary Key Employee Severance Benefits Plan
would be the same except that the benefits under the Voluntary Deferral Plan and
the Supplementary Voluntary Deferral Plan would be increased by implied interest
from the date of the Change in Control until the end of the month preceding the
month in which the benefit is distributed.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
For the 1998 fiscal year, decisions on various elements of executive
compensation were made by the Management Development and Corporate Performance
Committee, the Long-Term Compensation Committee and the Performance Share Plan
Committee. No officer, employee or former officer of SCANA or any of its
subsidiaries served as a member of the Long-Term Compensation Committee, the
Management Development and Corporate Performance Committee or the Performance
Share Plan Committee, except Mr. Timmerman who served as an ex-officio,
non-voting member of the Management Development and Corporate Performance
Committee and Mr. Gressette, who served as a member of the Long-Term
Compensation Committee. Although Mr. Timmerman served as a member of the
Management Development and Corporate Performance Committee, he did not
participate in any of its decisions concerning executive officer compensation.
Since January 1, 1998, SCANA and its subsidiaries have engaged in
business transactions with entities with which Mr. Amick (a member of the
Management Development and Corporate Performance Committee and the Long-Term
Compensation Committee) and Mrs. Freeman (a member of the Long-Term Compensation
Committee) are related.
Mr. Amick is President and a 20% owner of Team Amick Motor Sports LLC,
a business that owns and operates a NASCAR sanctioned racing car. This car
participates in the Busch Grand National Racing Series. During 1998, SCANA
participated in a shared sponsorship agreement with Team Amick Motor Sports LLC,
for an annual fee and related costs totaling $512,919. SCANA has recently
entered into a co-sponsorship agreement with Powertel, a wireless personal
communications services (PCS) provider, to sponsor the Team Amick racing car
during 1999. As of January 31, 1999 SCANA Communications, Inc., a subsidiary of
SCANA, owned a 29.2% interest in Powertel on a fully converted basis. SCANA's
portion of the racing car sponsorship is a base level of $800,000, with
incentives to increase the level of sponsorship up to an additional $200,000.
Powertel's sponsorship is at the $600,000 level. This agreement is subject to
termination within 30 days written notice.
Mrs. Freeman has a 28% beneficial ownership interest in Carolina
Wholesale Gas Company located in Spartanburg, South Carolina. During 1998,
Carolina Wholesale Gas Company rented cavern storage space for two million
gallons of propane from SCANA Propane Storage, Inc., a subsidiary of SCANA, at a
monthly rate of $10,000, for a total of $120,000. It is anticipated that this
arrangement will continue.
Directors Compensation
Board Fees
Officers of SCANA who are also directors do not receive additional
compensation for their service as directors. Since April 1998, compensation for
non-employee directors has included the following:
o an annual retainer of $19,400 (41% of the annual retainer fee is paid in
shares of SCANA Common Stock); o a fee of $2,000 for each board meeting
attended; o a fee of $1,000 for attendance at a committee meeting which is held
on a day other than a regular meeting of the board (no additional fees are paid
if a committee meeting is held on the same day as a board meeting); o a fee of
$200 for participation in a telephone conference meeting; o a fee of $1,000 for
attendance at an all-day conference; and o reimbursement for expenses incurred
in connection with all of the above.
Deferral Plan
Non-employee directors may participate in SCANA's Voluntary Deferral
Plan. This plan permits non-employee directors to defer receipt of all or part
of their fees (except the portion paid in shares of SCANA Common Stock) and
receive, upon ceasing to serve as a director, the amount that would have
resulted from investing the deferred amounts in an interest bearing savings
account.
Since January 1, 1998, the interest rate has been set at the announced
prime rate of Wachovia Bank, N.A. Mr. Rhodes, Mr. Cassels and Mr. Bennett were
the only directors who participated in the plan during 1998. Mr. Rhodes became a
participant in July 1987, Mr. Cassels in January 1994 and Mr. Bennett in
December 1997. During 1998, interest credited to Mr. Rhodes' deferral account
was $31,322; interest credited to Mr. Cassels' deferral account was $10,788 and
interest credited to Mr. Bennett's deferral account was $196.
Endowment Plan.
Upon election to a second term, a director becomes eligible to
participate in the SCANA Director Endowment Plan, which provides for SCANA to
make a tax deductible, charitable contribution totaling $500,000 to institutions
of higher education designated by the director. The plan is intended to
reinforce SCANA's commitment to quality higher education and to enhance its
ability to attract and retain qualified board members. A portion is contributed
upon retirement of the director and the remainder upon the director's death. The
plan is funded in part through insurance on the lives of the directors.
Designated in-state institutions of higher education must be approved by the
Chief Executive Officer of SCANA. Any out-of-state designation must be approved
by the Management Development and Corporate Performance Committee. The
designated institutions are reviewed on an annual basis by the Chief Executive
Officer to assure compliance with the intent of the program.
Other
As a Company retiree, Mr. Gressette receives a monthly benefit of
$9,488 under the Key Employee Retention Plan and a monthly benefit of $28,380
under the Retirement Plan and a SERP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SCANA:
The information called for by Item 12, "Security Ownership of
Certain Beneficial Owners and Management" is incorporated herein by reference to
the captions "Share Ownership of Directors, Nominees and Executive Officers" and
"Five Percent Owner of SCANA Common Stock" in the Company's definitive proxy
statement for the 1999 annual meeting of shareholders.
SCE&G:
The following table list shares of SCANA common stock beneficially owned
as of March 10, 1999 by each director, each nominee and each executive officer
named in the Summary Compensation Table on page 110.
SECURITY OWNERSHIP OF MANAGEMENT
Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature
Owner of Ownership 1 Owner of Ownership 1
B. L. Amick 4,074 W. Hayne Hipp 3,482
J. A. Bennett 1,146 K. B. Marsh 10,127
W. B. Bookhart, Jr. 19,101 F. C. McMaster 6,219
G. J. Bullwinkel 22,556 L. M. Miller 1,543
W. T. Cassels, Jr. 2,621 J. B. Rhodes 9,743
H. M. Chapman 6,589 J. L. Skolds 9,037
W. A. Darby 25,176 M. K. Sloan 1,215
E. T. Freeman 4,941 H. C. Stowe 100
L. M. Gressette, Jr. 61,716 W. B. Timmerman 40,775
D. M. Hagood 100
*Each of the directors, nominees and named executive officers owns less than 1%
of the shares outstanding.
- ----------
1 Includes shares owned by close relatives, the beneficial ownership of which is
disclaimed by the director, nominee or named executive officers, as follows:
Mr. Amick-480; Mr. Bookhart-4,613; Mr. Gressette-1,060; and
Mr. McMaster-2,000; and by all directors, nominees and executive officers
- - 8,238 in total.
Includes shares purchased through January 31, 1999, by the Trustee under
the SPSP.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SCANA:
The information called for by Item 13, "Certain Relationships and Related
Transactions" is incorporated herein by reference to the caption "Compensation
Committee Interlocks and Insider Participation" in the Company's definitive
proxy statement for the 1999 annual meeting of shareholders.
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 on Executive Compensation" and the "Performance Graph" included in
the Company's definitive proxy statement for the 1999 annual meeting of
shareholders shall not be incorporated by reference into any such filings.
SCE&G:
For information regarding certain relationships and related
transactions, see Item 11, "Executive Compensation" at "Compensation Committee
Interlocks and Insider Participation."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form
10-K:
(1) Financial Statements and Schedules:
Independent Auditor's Reports on the financial statements
for SCANA and SCE&G are listed under Item 8 herein.
The financial statements and supplementary financial data
filed as part of this report for SCANA and SCE&G are listed
under Item 8 herein.
(2) Exhibits
Exhibits required to be filed with this Annual Report on
Form 10-K are listed in the Exhibit Index following the
signature pages. Certain of such exhibits which have
heretofore been filed with the Securities and Exchange
Commission and which are designated by reference to their
exhibit number in prior filings are hereby incorporated
herein by reference and made a part hereof.
Pursuant to rule 15d-21 promulgated under the Securities
Exchange Act of 1934, the annual report for the Company's
employee stock purchase 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) of Regulation S-K,
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.
(b) Reports on Form 8-K during the fourth quarter of 1998 were as follows:
SCANA filed a current report on Form 8-K:
Date of report: December 15, 1998
Item reported: Item 5
SCE&G filed a current report on Form 8-K:
Date of report: December 15, 1998
Item reported: Item 5
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. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
SCANA CORPORATION
By: s/W. B. Timmerman, Chairman of the Board,
President, Chief Executive Officer and Director
DATE: March 18, 1999
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: s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Date: March 18, 1999
By: s/K. B. Marsh
K. B. Marsh, Senior Vice President - Finance,
Chief Financial Officer and Controller
(Principal Financial and Accounting Officer)
Date: March 18, 1999
Directors:
B. L. Amick J. A. Bennette
W. B. Bookhart, Jr. W. T. Cassels, Jr.
H. M. Chapman E. T. Freeman
L. M. Gressette, Jr. W. Hayne Hipp
F. C. McMaster L. M. Miller
J. B. Rhodes M. K. Sloan
By: s/K. B. Marsh
(K. B. Marsh, Attorney-in-fact)
Date: March 18, 1999
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. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
By: s/J. L. Skolds
J. L. Skolds, President and Chief Operating Officer
Date: March 18, 1999
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.
By: s/W. B. Timmerman
W. B. Timmerman Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
Date: March 18, 1999
By: s/K. B. Marsh
K. B. Marsh, Senior Vice President - Finance,
Chief Financial Officer and Controller
(Principal Financial Officer)
Date: March 18, 1999
By: s/J. E. Addison
J. E. Addison, Vice President and Controller
(Principal Accounting Officer)
Date: March 18, 1999
Directors:
B. L. Amick J. A. Bennette
W. B. Bookhart, Jr. W. T. Cassels, Jr.
H. M. Chapman E. T. Freeman
L. M. Gressette, Jr. W. Hayne Hipp
F. C. McMaster L. M. Miller
J. B. Rhodes M. K. Sloan
By: s/K. B. Marsh
(K. B. Marsh, Attorney-in-Fact)
Date: March 18, 1999
EXHIBIT INDEX
Applicable to
Form 10-K of
Exhibit
No. SCANA SCE&G Description
2.01 X Agreement and Plan of Merger, dated as of February 16,
1999, by and among Public Service Company of North
Carolina, Incorporated, SCANA Corporation , New Sub I,
Inc. and New Sub II, Inc. (Filed as Exhibit 10.1 to Form
8-K on February 23, 1999)
3.01 X Restated Articles of Incorporation of SCANA as adopted on
April 26, 1989 (Filed as Exhibit 3-A to Registration
Statement No. 33-49145)
3.02 X Restated Articles of Incorporation of SCE&G, as
adopted on December 15, 1993 (Filed as Exhibit
3-A to Form 10-Q for the quarter ended June 30,
1994, File No. 1-3375)
3.03 X Articles of Amendment of SCANA, dated April 27, 1995
(Filed as Exhibit 4-B to Registration Statement No.
33-62421)
3.04 X Articles of Amendment of SCE&G, dated June 7, 1994 filed
June 9, 1994 (Filed as Exhibit 3-B to Form 10-Q for the
quarter ended June 30, 1994, File No. 1-3375)
3.05 X Articles of Amendment of SCE&G, dated November 9, 1994
(Filed as Exhibit 3-C to Form 10-K
for the year ended December 31, 1994, File No. 1-3375)
3.06 X Articles of Amendment of SCE&G, dated December 9, 1994
(Filed as Exhibit 3-D to Form 10-K
for the year ended December 31, 1994, File No. 1-3375)
3.07 X Articles of Correction of SCE&G, dated January 17, 1995
(Filed as Exhibit 3-E to From 10-K
for the year ended December 31, 1994, File No. 1-3375)
3.08 X Articles of Amendment of SCE&G, dated January 13, 1995
and filed January 17, 1995 (Filed as Exhibit 3-F to Form
10-K for the year ended December 31, 1994, File No.
1-3375)
3.09 X Articles of Amendment of SCE&G, dated March 31, 1995
(Filed as Exhibit 3-G to Form 10-Q for
the quarter ended March 31, 1995, File No. 1-3375)
3.10 X Articles of Correction of SCE&G - Amendment to Statement
filed March 31, 1995, dated December 12, 1995 (Filed as
Exhibit 3-H to Form 10-K for the year ended
December 31, 1995,Filed No. 1-3375)
3.11 X Articles of Amendment of SCE&G, dated December 13, 1995
(Filed as Exhibit 3-I to Form 10-K
for the year ended December 31, 1995, File No. 1-3375)
3.12 X Articles of Amendment of SCE&G, dated February 18, 1997
(Filed as Exhibit 3-L to Registration Statement
No. 333-24919)
3.13 X Articles of Amendment of SCE&G, dated February 21, 1997
(Filed as Exhibit 3-L to Form 10-Q
for the quarter ended March 31, 1997)
3.14 X Articles of Amendment of SCE&G, dated April 22, 1997
(Filed as Exhibit 3-M to Form 10-Q for
the quarter ended June 30, 1997)
3.15 X Copy of By-Laws of SCANA as revised and amended on
December 17, 1997 (Filed as Exhibit 3-C
to Form 10-K for the year ended December 31, 1997)
Applicable to
Form 10-K of
Exhibit
No. SCANA SCE&G Description
3.16 X Copy of By-Laws of SCE&G as revised and amended on
December 17, 1997 (Filed as Exhibit 3-J
to Form 10-K for the year ended December 31, 1997)
4.01 X Articles of Exchange of South Carolina Electric and Gas
Company and SCANA Corporation (Filed as Exhibit 4-A to
Post-Effective Amendment No. 1 to Registration Statement
No. 2-90438)
4.02 X Copy of Supplemental Executive Retirement Plan
as amended and restated effective as of October
21, 1997 (Filed as Exhibit 10-A to Form 10-K for
the year ended December 31, 1997)
4.03 X Indenture dated as of November 1, 1989 to The Bank of
New York, Trustee (Filed as Exhibit 4-A to Registration
No.
33-32107)
4.04 X X Indenture dated as of January 1, 1945, from the South
Carolina Power Company (the "Power Company") to Central
Hanover Bank and Trust Company, as Trustee, as
supplemented by three Supplemental Indentures dated
respectively as of May 1, 1946, May 1, 1947 and July 1,
1949 (Filed as Exhibit 2-B to Registration Statement No.
2-26459)
4.05 X X Fourth Supplemental Indenture dated as of April 1,
1950, to Indenture referred to in Exhibit 4.04, pursuant
to which SCE&G assumed said Indenture (Exhibit 2-C to
Registration Statement No. 2-26459)
4.06 X X Fifth through Fifty-second Supplemental Indenture
referred to in Exhibit 4.04 dated as of the dates
indicated below and filed as exhibits to the Registration
Statements and 1934 Act reports whose file numbers are set
forth below:
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26489
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-O to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 2-B to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
Applicable to
Form 10-K of
Exhibit
No. SCANA SCE&G Description
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 2-A-3 to Registration No. 33-38580
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
June 1, 1986 Exhibit 4-D to Registration No. 33-49421
February 1, 1987 Exhibit 4-D to Registration No. 33-49421
September 1, 1987 Exhibit 4-D to Registration No. 33-49421
January 1, 1989 Exhibit 4-D to Registration No. 33-49421
January 1, 1991 Exhibit 4-D to Registration No. 33-49421
February 1, 1991 Exhibit 4-D to Registration No. 33-49421
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
4.04 X X Indenture dated as of April 1, 1993 from South
Carolina Electric & Gas Company to NationsBank of
Georgia, National Association (Filed as Exhibit 4.07 to
Registration Statement No.
33-49421)
4.08 X X First Supplemental Indenture to Indenture referred to
in Exhibit 4.07 dated as of June 1, 1993 (Filed as
Exhibit 4-G to Registration Statement No. 33-49421)
4.09 X X Second Supplemental Indenture to Indenture referred to
in Exhibit 4.07 dated as of June 15, 1993 (Filed as
Exhibit 4-G to Registration Statement No. 33-57955)
4.10 X X Trust Agreement for SCE&G Trust I (Filed as Exhibit 4-I
to Form 10-K for the year ended December 31, 1997)
4.11 X X Certificate of Trust for SCE&G Trust I (Filed as Exhibit
4-I to Form 10-K for the year ended December 31, 1997)
4.12 X X Junior Subordinated Indenture for SCE&G Trust I
(Filed as Exhibit 4-K to Form 10-K for the year ended
December 31, 1997)
4.13 X X Guarantee Agreement for SCE&G Trust I (Filed as Exhibit
4-L to Form 10-K for the year ended December 31, 1997)
4.14 X X Amended and Restated Trust Agreement for SCE&G Trust
I (Filed as Exhibit 4-M to Form 10-K for the year ended
December 31, 1997)
Applicable to
Form 10-K of
Exhibit
No. SCANA SCE&G Description
10.01 X Copy of SCANA Voluntary Deferral Plan as amended through
October 21, 1997 (Filed herewith at page 122)
10.02 X Copy of SCE&G Supplemental Executive Retirement Plan
(Filed as Exhibit 10A to Form 10-K for the year ended
December 31, 1997)
10.03 X Copy of SCANA Supplemental Executive Retirement Plan (Filed
herewith at page 148)
10.04 X Copy of SCANA Supplementary Voluntary Deferral Plan as
amended and restated through October 21, 1997 (Filed as
Exhibit 10-B to Form 10-K for the year ended December 31,
1997)
10.05 X Copy of SCANA Key Executive Severance Benefit Plan as
amended and restated effective as of October 21, 1997
(Filed as Exhibit 10-C to Form 10-K for the year ended
December 31, 1997)
10.06 X Copy of SCANA Supplementary Key Executive Severance Benefit
Plan as amended and restated effective October 21, 1997
(Filed herewith on page 165)
10.07 X Copy of SCANA Performance Share Plan as amended and
restated effective January 1, 1998 (Filed herewith at page
187)
10.08 X Form of Agreement under SCANA Key Employee Retention Plan as
amended and restated effective as of October 21, 1997 (Filed
as Exhibit 10-E to Form 10-K for the year ended
December 31, 1997)
10.09 X Description of SCANA Whole Life Option (Filed as Exhibit
10-F to Form 10-K for the year ended December 31, 1991,
under cover of Form SE, File No. 1-8809)
10.10 X Description of SCANA Corporation Annual Incentive Plan
(Filed as Exhibit 10-G to Form 10-K for the year ended
December 31, 1991, under cover of Form SE, File No. 1-8809)
12.01 X X Statements Re computation of Ratios (Filed herewith at
page 124)
21.01 X Subsidiaries of the Registrant (Filed herewith at page 20)
23.01 X Consents of Experts and Counsel (Filed herewith at page 132)
23.02 X Consents of Experts and Counsel (Filed herewith at page 133)
24.01 X Power of Attorney (Filed herewith at page 118)
24.02 X Power of Attorney (Filed herewith at page 119)
27.01 X Financial Data Schedule (Filed herewith)
27.02 X Financial Data Schedule (Filed herewith)