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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, 1999
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
1426 Main Street
Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
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
SCANA: 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. ( )
SCE&G: 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 amendments to this Form 10-K. (X)
The aggregate market value of voting stock held by non-affiliates of
SCANA Corporation was $2,487,726,284 at February 29, 2000, based on a price of
$23.8125. The total number of shares outstanding at February 29, 2000 was
104,730,049. 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 29, 2000, there were issued and outstanding 40,296,147 Common Shares,
$4.50 par value, of South Carolina Electric & Gas Company, held in entirety by
SCANA Corporation.
Documents incorporated by reference: Specified sections of SCANA
Corporation's 2000 Proxy Statement, dated March 17, 2000, in connection with its
2000 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 ................................................. 16
Item 3. Legal Proceedings........................................... 18
Item 4. Submission of Matters to a Vote of Security Holders ........ 18
Corporate Structure ................................................. 19
Executive Officers of SCANA Corporation ............................. 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................ 21
Item 6. Selected Financial Data..................................... 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.. 40
Item 8. Financial Statements and Supplementary Data................. 41
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 ................................... 109
Item 12. Security Ownership of Certain Beneficial Owners
and Management ......................................... 115
Item 13. Certain Relationships and Related Transactions ........... 115
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K ............................................ 116
SIGNATURES.............................................................. 123
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
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
DT....................... Dekatherm
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
MGP...................... Manufactured Gas Plant
Mhz...................... Megahertz
MMCF..................... Million Cubic Feet
MW....................... Megawatt
NEPA..................... National Energy Policy Act of 1992
NCUC..................... North Carolina Utilities Commission
NRC...................... United States Nuclear Regulatory Commission
PCS...................... Personal Communications Service
Pipeline Corporation..... South Carolina Pipeline Corporation
PRP...................... Potentially Responsible Party
PSC...................... The Public Service Commission of South Carolina
PSNC..................... Public Service Company of North Carolina, Incorporated
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 registered as a public utility holding
company under PUHCA on February 10, 2000, concurrent with the completion of its
merger with PSNC. 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 an indirect subsidiary. SCANA
and its subsidiaries (the Company) had 5,488 full-time, permanent employees as
of February 29, 2000 as compared to 4,697 full-time, permanent employees as of
December 31, 1998. 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 14
direct, wholly owned subsidiaries that are engaged in the functionally distinct
operations described below. It also has investments in two LLCs: one has built
and operates a cogeneration facility in Charleston, South Carolina and the other
has constructed and operates a lime production facility in Charleston, South
Carolina.
Information with respect to major segments of business for the years
ended December 31, 1999, 1998 and 1997 is contained in Management's Discussion
and Analysis of Financial Condition and Results of Operations and in Note 11 of
the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA for SCANA and SCE&G. All such information is
incorporated herein by reference.
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 heating requirements.
SCE&G's electric service area extends into 24 counties covering more than
15,000 square miles in the central, southern and southwestern portions of South
Carolina. The service area for natural gas encompasses all or part of 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 2.4 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. 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. On November 10, 1999 a
wholly owned subsidiary of Pipeline Corporation sold its 62-mile, six-inch
propane pipeline that connects with the propane storage facility formerly owned
by SCANA Propane Storage, Inc. Pipeline Corporation's, subsidiary continues to
maintain this pipeline.
On February 10, 2000 SCANA completed its acquisition of PSNC. PSNC is a
public utility engaged primarily in transporting, distributing and selling
natural gas to approximately 351,000 residential, commercial and industrial
customers in 31 counties in North Carolina. The industrial customers of PSNC
include manufacturers of textiles, chemicals, ceramics and clay products, glass,
automotive products, minerals, pharmaceuticals, plastics, metals, electronic
equipment, furniture and a variety of food and tobacco products. PSNC was
organized in 1938. PSNC, through wholly owned, non-regulated subsidiaries,
conducts gas brokering activities, refuels natural gas vehicles and converts
gasoline-fueled vehicles to natural gas.
Nonregulated Businesses
Energy Marketing markets electricity, natural gas and other light
hydrocarbons primarily in the southeast. In addition, Energy Marketing markets
natural gas to approximately 431,000 customers in Georgia's deregulated natural
gas market. Energy Marketing also provides energy-related risk management
services to producers and customers.
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. SCANA Communications Holdings, Inc., a
Delaware corporation and a wholly owned subsidiary of SCI, has investments in
Powertel, Inc., ITC Holding Company, Inc., ITC^DeltaCom, Inc., and Knology,
Inc., which are telecommunications services companies 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
services.
Primesouth, Inc. is engaged in power plant management and maintenance
services.
SCANA Resources, Inc. conducts energy-related businesses and services.
On November 10, 1999 substantially all of the assets of SCANA Propane
Gas, Inc., SCANA Propane Storage, Inc. and C&T Pipeline, LLC (a wholly owned
subsidiary of Pipeline Corporation) were sold.
Service Company
SCANA Services, Inc. provides administrative, management and other services
to the subsidiaries and business units within
SCANA.
COMPETITION
For a discussion of the impact of competition, see the Competition
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations for SCANA and SCE&G.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The Company's cash requirements arise primarily from SCE&G's operational
needs, the Company'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. SCANA'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 the Company's
capital requirements, see Regulatory Matters in the Liquidity and Capital
Resources section of Management's Discussion and Analysis of Financial Condition
and Results of Operations for SCANA and SCE&G.
During 2000 the Company is expected to meet its capital requirements
principally 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 12 months and for the foreseeable
future.
The Company's current estimates of its cash requirements for construction
and nuclear fuel expenditures, which are subject to continuing review and
adjustment, for 2000 and the two-year period 2001-2002 are as follows:
- -------------------------------------- ----------------------- ----------------
Type of Facilities 2001-2002 2000
(Millions of Dollars)
South Carolina Electric & Gas Company:
Electric Plant:
Generation $322 $112
Transmission 38 21
Distribution 156 76
Other 14 14
Nuclear Fuel 33 31
Gas 38 20
Common 29 24
Other 1 1
---- ----
Total 631 299
Other Companies Combined 130 99
---- -----
Total $761 $398
- --------------------------------------------------------------- ----------------
The above estimates exclude AFC.
During 1999 SCE&G and GENCO expended approximately $56.5 million and
$1.5 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 2000, included in the table above, are estimated to
cost approximately $29.1 million and $0.9 million, respectively.
In addition to the capital requirements for 2000 described above, the
Company and SCE&G will require approximately $373.3 million and $198.3 million,
respectively, to refund and retire outstanding securities and obligations. For
the years 2001-2004, the Company has an aggregate of $520.4 million of long-term
debt maturing, which includes an aggregate of $293.4 million for SCE&G and $2.2
million of purchase or sinking fund requirements for SCE&G's preferred stock. In
addition, SCANA borrowed a total of $700 million from February 8-10, 2000,
maturing within three years, to consummate the acquisition of PSNC. SCE&G's
long-term debt maturities for the years 2001-2004 include approximately $79.2
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 percent 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. The
facility began operations in March 1999. Financing for the facility of
approximately $139.8 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 $52 million from Cogen, alleging
that it incurred construction cost overruns relating to the facility 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 and SCE&G do not believe that the resolution of this
issue will have a material impact on 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. At December 31, 1999 SCANA had
registered with the SEC and available for issuance $1.0 billion under this
program. The proceeds from the sales of these securities may be used to
refinance bank borrowings and other privately sold indebtedness incurred in
connection with the acquisition of PSNC. In addition, the proceeds 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.
SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945
(Old Mortgage), contains provisions prohibiting the issuance of additional bonds
thereunder (Class A Bonds) unless net earnings (as therein defined) for 12
consecutive months out of the 18 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, 1999 the Bond Ratio
was 6.01. The Old Mortgage allows the issuance of additional Class A Bonds to an
additional principal amount equal to (i) 70 percent of unfunded net property
additions (which unfunded net property additions totaled approximately $1,250
million at December 31, 1999), (ii) retirements of Class A Bonds (which
retirement credits totaled $91.8 million at December 31, 1999), 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 $715 million were available for such purpose at December 31,
1999). New Bonds will be issuable under the New Mortgage only if adjusted net
earnings (as therein defined) for 12 consecutive months out of the 18 months
immediately preceding the month of issuance are at least twice the annual
interest requirements on all outstanding bonds (including Class A Bonds) and New
Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1999
the New Bond Ratio was 5.95.
The following additional financing transactions have occurred since
January 1, 1999:
o On March 9, 1999 SCE&G issued $100 million of First Mortgage Bonds having
an annual interest rate of 6 1/8 percent and maturing on March 1, 2009. The
proceeds from the sale of these bonds were used to reduce short-term debt.
o On June 29, 1999 SCANA issued $150 million one-year floating rate
medium-term notes maturing on July 14, 2000. The interest rate on the notes
is reset monthly and is based on a one-month LIBOR plus 35 basis points.
The proceeds from these notes were used to reduce short-term bank debt.
o On July 15, 1999 SCANA paid at maturity all $43 million principal amount
outstanding of its 7.17 percent medium-term notes.
o On October 8, 1999 SCANA paid at maturity all $30 million principal amount
outstanding of its 6.6 percent medium-term notes.
o On November 1, 1999 SCANA's shelf registration statement filed with the SEC
became effective, providing for the issuance of up to an additional $1
billion in medium-term notes.
o On December 1, 1999 SCANA signed a credit agreement with banks for a
maximum of $300 million for a three-year term loan, all of which was drawn
on February 10, 2000 to consummate SCANA's acquisition of PSNC.
o On February 8, 2000 the Company issued $400 million of two-year floating
rate notes maturing February 8, 2002. The interest rate on the notes is
reset quarterly based on a three-month LIBOR plus 50 basis points. The
proceeds from these privately sold notes were used to consummate SCANA's
acquisition of PSNC.
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 percent 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 12 months or less but not later than December 31, 2001. GENCO
has not sought such authorization.
At December 31, 1999 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, 1999
totaled $285 million. SCE&G commercial paper outstanding at December 31, 1999
and December 31, 1998 was $143.1 million and $125.2 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 12 consecutive
months immediately preceding the month of issuance are at least one and one-half
times the aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended December 31, 1999 the
Preferred Stock Ratio was 1.79.
PSNC has committed lines of credit with five commercial banks that vary
in amount monthly depending upon seasonal requirements and a five-year revolving
line of credit with one bank. These lines of credit range from a minimum of $55
million to a winter-period maximum of $75 million. PSNC also has total
uncommitted lines of credit ranging from $70 million to $100 million.
As a result of SCANA's acquisition of PSNC that was consummated on
February 10, 2000, SCANA and PSNC shareholders received cash and shares of SCANA
common stock. PSNC shareholders were paid $212 million in cash and 17,413,929
shares of SCANA common stock. SCANA shareholders were paid $488 million in cash
and 87,316,120 shares of SCANA common stock. On September 17, 1999 an additional
4,000,000 shares of SCANA common stock were registered for sale under the SPSP.
On September 9, 1999 an additional 3,000,000 shares of SCANA common stock were
registered for sale under the Investor Plus Plan. During 1999, 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 2.98,
3.67, 3.64, 3.60 and 3.00 for the years ended December 31, 1999, 1998, 1997,
1996 and 1995, respectively. For SCE&G these ratios were 3.71, 4.40, 3.85, 3.80
and 3.41 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 12 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 a revolving credit agreement which expires
December 19, 2000. 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, 1999. At December 31, 1999
commercial paper outstanding was approximately $70.2 million at a weighted
average interest rate of 6.44 percent. (See Note 4 of Notes to Consolidated
Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 1999 residential sales of electricity accounted for 41% of electric
sales revenues; commercial sales 30%; industrial sales 19%; sales for resale 4%;
and all other 6%. The Company's KWH sales by classification for the years ended
December 31, 1999 and 1998 are presented below:
Sales
KWH (Millions)
- --------------------------------------------------------------------------------
CLASSIFICATION 1999 1998 % CHANGE
- --------------------------------------------------------------------------------
Residential 6,269 6,324 (1%)
Commercial 5,950 5,899 1%
Industrial 6,140 5,824 5%
Sales for resale 1,189 1,125 6%
Other 518 536 (3%)
- -------------------------------------------------- ------------------ ---------
Total Territorial 20,066 19,708 2%
Negotiated Market Sales Tariff 1,678 1,495 12%
================================================== =============================
Total 21,744 21,203 3%
================================================== =============================
Sales for resale includes electricity furnished for resale to two
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 1999 include sales to 32 investor-owned
utilities and registered marketers, seven electric cooperatives, two
municipalities and four federal/state electric agencies. During 1998, sales
under the Negotiated Market Sales Tariff included sales to 34 investor-owned
utilities, three electric cooperatives, one municipality and four federal/state
electric agencies.
The electric sales volume from residential sales decreased for 1999
primarily as a result of milder weather. During 1999 the Company recorded a net
increase of 6,105 customers, increasing its total customers to 523,552. The
all-time peak demand of 4,158 MW was set on August 18, 1999.
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 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 the 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 1997-1999.
1999 1998 1997
---- ---- ----
Nuclear:
Per million BTU $ .46 $ .46 $ .47
Coal:
SCE&G
Per ton $39.37 $38.19 $38.22
Per million BTU 1.57 1.54 1.50
GENCO:
Per ton $41.46 $41.67 $44.49
Per million BTU 1.61 1.61 1.63
Weighted Average Cost of All Fuels:
Per million BTU $ 1.50 $ 1.49 $ 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
1997-1999 and the estimates for 2000 and 2001.
Percent of Total KWH Generated
------------------------------------------------------------
Estimated Actual
--------------------- ------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Coal 70% 73% 73% 69% 71%
Nuclear 24 21 22 25 24
Hydro 5 5 4 5 5
Natural Gas & Oil 1 1 1 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, 1999
SCE&G had approximately a 59-day supply of coal in inventory and GENCO had
approximately a 52-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 SCANA's existing contracts. Contracts for the purchase of
coal represent approximately 75-80 percent of expected requirements for 2000.
Contract coal is purchased from 11 suppliers located in eastern
Kentucky, Tennessee, southwest Virginia and West Virginia. Contract commitments,
which expire at various times from 2000 through 2008, approximate 5.3 million
tons annually. Sulfur restrictions on the contract coal range from 0.75 percent
to 2 percent.
The Company believes that SCE&G's and GENCO's operations are in
compliance with all existing regulations relating to the discharge of sulfur
dioxide and nitrogen oxides. The Company is unaware that any more stringent
sulfur content requirements for existing plants are contemplated at the state
level by DHEC.
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) 15-18 2005
Fabrication Westinghouse Electric Corporation 15-21 2009
(1) A region represents approximately one-third to one-half of the nuclear
core in the reactor at any one time. Region 15 will be loaded in 2000.
(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
2006 and expects to be able to expand its storage capacity to accommodate the
spent fuel output for the life of the plant through spent fuel pool reracking,
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 October 2000 that is
expected to last approximately 30 days.
Decommissioning
For information regarding the decommissioning of Summer Station, see
Note 1H, Nuclear Decommissioning, of the Notes to Consolidated Financial
Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for
SCANA and SCE&G.
GAS OPERATIONS
Gas Sales - Regulated
In 1999 the Company's residential sales accounted for 24% of gas sales
revenues; commercial sales 18%; industrial sales 46%; sales for resale 12%.
During the same period, SCE&G's residential sales accounted for 42% of gas sales
revenues; commercial sales 32%; industrial sales 26%. Dekatherm sales by
classification for the years ended December 31, 1999 and 1998 are presented
below:
Sales
Dekatherms (000)
- --------------------------------------------------------------------------------
SCANA SCE&G
CLASSIFICATION 1999 1998 % Change 1999 1998 % Change
- --------------------------------------------------------------------------------
Residential 11,823 11,917 (0.8%) 11,823 11,917 (0.8%)
Commercial 11,781 11,383 3.5% 11,699 11,294 3.6%
Industrial 61,192 61,251 (0.1%) 17,958 17,314 3.7%
Sales for Resale 15,947 15,744 1.3% - - -
Transportation gas 4,227 4,435 (4.7%) 1,975 2,004 (1.4%)
- --------------------------------------------------------------------------------
Total 104,970 104,730 0.2% 43,455 42,529 2.2%
================================================================================
The Company's and SCE&G's gas sales volume increased for 1999 primarily
as a result of customer growth and customer expansion. During 1999 the Company
recorded a net increase of 3,404 customers, increasing its total customers to
260,362. SCE&G recorded a net increase of 3,404 gas customers, increasing its
total customers to 260,246.
The demand for gas is affected by 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 daily volume of gas that 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 266,495 dekatherms. The contract allows SCE&G
to receive amounts in excess of this demand based on availability.
During 1999 Pipeline Corporation's average cost per MCF of natural gas
purchased for resale, excluding firm service demand charges, was $2.54 compared
to $2.39 during 1998. SCE&G's average cost per MCF was $3.73 and $3.67 during
1999 and 1998, 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 1,178
MMCF were in storage at December 31, 1999. 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 5,012 MMCF were
in storage on December 31, 1999.
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 - Nonregulated
Energy Marketing markets natural gas and provides energy-related risk
management services to producers and consumers, including the deregulated
Georgia marketplace. 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
On November 10, 1999 substantially all of the assets of SCANA Propane
Gas, Inc., SCANA Propane Storage, Inc. and C & T Pipeline, LLC (a wholly owned
subsidiary of Pipeline Corporation) were sold.
REGULATION
General
SCANA became a registered public utility holding company under PUHCA on
February 10, 2000, concurrent with completion of its merger with PSNC. SCANA and
its subsidiaries are subject to the jurisdiction of the SEC as to financings,
acquisitions and diversifications, affiliate transactions and other matters.
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.
Pipeline Corporation is subject to the jurisdiction of the PSC as to
gas rates, service, accounting and other matters.
PSNC is subject to the jurisdiction of the NCUC as to gas rates, issuance
of securities, (other than notes with a maturity of two years or less or
renewals of notes over a six-year or shorter period), service, accounting 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 License Expiration
Neal Shoals 2036
Stevens Creek 2025
Columbia 2000
Saluda 2007
Parr Shoals 2020
Fairfield Pumped Storage 2020
The current license for Columbia expires on June 30, 2000. SCE&G filed
an application for a new license for Columbia on June 30, 1998. The application
was officially accepted for filing by FERC notice dated December 23, 1999.
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 SCE&G'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. In addition, Summer Station has received a category
one rating from the Institute of Nuclear Power Operations (INPO) in seven out of
the last eight evaluations. The category one rating is the highest given by INPO
for a nuclear plant's overall operations.
National Energy Policy Act of 1992 and FERC 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 the Competition section of Management's
Discussion and Analysis of Financial Condition and Results of Operations for
SCANA and SCE&G 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 will 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 of Financial Condition and Results of Operations for
SCANA 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 12-month period, adjusted for any
overcollection or undercollection from the preceding 12-month period. SCE&G has
the right to request a formal proceeding at any time should circumstances
dictate such a review. In the April 1999 annual review of the fuel cost
component of electric rates, the PSC increased the rate to 13.37 mills per KWH.
SCE&G's gas rate schedules and contracts include mechanisms that 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 1999 review the PSC increased the base cost of gas to 54.334 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. For a more complete discussion of how these
regulations and standards impact the Company and SCE&G, see the Environmental
Matters section of Management's Discussion and Analysis of Financial Condition
and Results of Operations for SCANA and SCE&G.
Capital Expenditures
In the years 1997 through 1999, the Company's capital expenditures for
environmental control amounted to approximately $103.7 million (including
approximately $94.6 million for SCE&G). This was in addition to expenditures
included in "Other operation" and "Maintenance" expenses, which were
approximately $18.2 million, $18.8 million, and $17.1 million during 1999, 1998
and 1997, respectively (including approximately $15.0 million, $16.2 million and
$15.3 million for SCE&G during 1999, 1998 and 1997, respectively). It is not
possible to estimate all future costs for environmental purposes, but forecasts
for capitalized expenditures for the Company are $4.9 million for 2000 and
$118.5 million for the four-year period 2001 through 2004 (including $4.4
million for 2000 and $63.2 million for the four-year period 2001 through 2004
for SCE&G). These expenditures are included in the Company's and SCE&G's
construction program.
The EPA has issued rules on regional ozone control which require revised
State Implementation Plans for 22 eastern and midwestern states and the District
of Columbia. These rules are being challenged in court by various states and
industry and other interests, including the State of South Carolina. The
outcomes of the court and future regulatory proceedings are uncertain. The
Company may incur up to $50 million for additional capital improvements in
addition to those already forecasted in the preceding paragraph. These
additional costs, if incured, would all be for SCE&G 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 2006 and
expects to be able to expand its storage capacity to accommodate the spent
nuclear fuel output for the life of the plant through spent fuel pool reracking,
dry cask storage or other technology as it becomes available. The Act also
imposes on utilities the primary responsibility for storage of their spent
nuclear fuel until the repository is available.
OTHER MATTERS
With regard to SCE&G's insurance coverage for Summer Station, reference
is made to Note 10Bof the Notes to Consolidated Financial Statements, which is
incorporated herein by reference.
On November 10, 1999 substantially all of the assets of SCANA Propane
Gas, Inc., SCANA Propane Storage, Inc., and C&T Pipeline, LLC (a wholly owned
subsidiary of Pipeline Corporation) were sold for approximately $94.5 million.
The resulting after-tax gain of $29.9 million was recorded in "Other Income."
Proceeds from the sale were used to reduce short-term debt.
For a description of the Company's investments in various
telecommunications companies, see Other in the Liquidity and Capital Resources
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations for SCANA.
For a discussion of the results of measures taken to address the Year
2000 issue, see Other Matters in the Liquidity and Capital Resources section of
Management's Discussion and Analysis of Financial Condition and Results of
Operations for SCANA and SCE&G.
ITEM 2. PROPERTIES
SCANA owns no significant property other than the capital stock of each
of its subsidiaries. It 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 an indirect subsidiary. It also
has investments in two LLC's: one has built and operates a cogeneration facility
in Charleston, South Carolina and the other has constructed and operates a lime
production facility in Charleston, South Carolina.
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, is as follows:
Net Generating
Present Year Capacity
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 700,000
Williams (1) Coal Goose Creek, SC 1973 600,000
Summer (2) Nuclear Parr, SC 1984 635,000
D-Area (3) Coal DOE Savannah River
Site, SC 1995 38,000
Cope Coal Cope, SC 1996 410,000
Westvaco * Charleston, SC 1999 55,000
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
Urquhart #4 Gas/Oil Beech Island, SC 1999 48,000
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
--------
4,483,000
(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 receives shaft horse power from Cogen South, LLC to operate its
generator. Cogen South, LLC is owned 50 percent by SCANA and 50 percent by
Westvaco.
SCE&G owns 447 substations having an aggregate transformer capacity of
22,360,586 KVA. The transmission system consists of 3,164 miles of lines and the
distribution system consists of 16,571 pole miles of overhead lines and 3,771
trench miles of underground lines.
GAS
Natural Gas
SCE&G's gas system consists of approximately 12,300 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.
PSNC's gas system consists of approximately 761 miles of transmission
pipeline of up to 24 inches in diameter that connect its distribution systems
with Transco. PSNC's distribution system consists of approximately 6,857 miles
of distribution mains and related service facilities. PSNC also owns, through a
wholly owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a
105-mile transmission pipeline.
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 73 MMCF
per day. These facilities can store the equivalent of 430 MMCF of natural gas.
TRANSIT
SCE&G owns 49 motor coaches used in the operation of the Columbia
transit system. The Columbia system is comprised of 17 routes covering 177
miles. SCE&G intends to dispose of its investment in the Columbia transit system
within two years. Management is uncertain as to what the costs associated with
the disposition of the transit system will be.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Item 1, BUSINESS RATE
MATTERS, Environmental Matters in the Liquidity and Capital Resources section of
Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS, and Note 10 of Notes to Consolidated Financial Statements
appearing in Item 8., FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
CORPORATE STRUCTURE
SCANA CORPORATION
A holding company, owning the direct, wholly
owned subsidiaries listed below
SOUTH CAROLINA ELECTRIC & SCANA COMMUNICATIONS, INC.
- -------------------------- --------------------------
GAS COMPANY Provides fiber optic telecommunications
- ----------- in South Carolina, a public safety radio
Generates and sells electricity communications network, tower
and gas to wholesale and retail construction, management and rental
customers, sells and transports services for wireles providers and
natural gas at retail and invests in telecommunications companies.
provides public transit service
in Columbia.
SOUTH CAROLINA GENERATING SCANA ENERGY MARKETING, INC.
COMPANY, INC. Markets electricity, natural gas and
Owns and operates Williams Station other light hydrocarbons primarily in
and sells electricity to SCE&G. the southeast. Markets natural gas in
Georgia's deregulated natural gas
SOUTH CAROLINA FUEL market. Provides energy-related risk
COMPANY, INC. management services to producers and
Acquires, owns and provides customers.
financing for SCE&G's nuclear fuel,
fossil fuel and sulfur dioxide
emission allowances. SERVICECARE, INC.
Provides energy-related products,
SOUTH CAROLINA PIPELINE service contracts on home appliances
CORPORATION and home security services.
Purchases, sells and transports
natural gas to wholesale and direct PRIMESOUTH, INC.
industrial customers. Owns and Engages in power plant management and
operates two LNG plants for the maintenance services.
liquefactin, storage and
regasification of natural gas.
SCANA RESOURCES, INC.
PUBLIC SERVICE COMPANY OF Conducts energy-related businesses and
- ------------------------- services.
NORTH CAROLINA
- -------------- SCANA SERVICES, INC.
Purchases, sells and transports Provides administrative, management
natural gas to retail customers, and other services to the subsidiaries
markets natural gas, refuels natural and business units within SCANA
gas vehicles and refuels natural gas Corporation.
vehicles and converts gasoline-fueled
vehicles to natural gas.
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 53 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
J. L. Skolds 49 President and Chief
Operating Officer, SCE&G 1996-present
Senior Vice President -
Generation, SCE&G *-1996
Senior Vice President -
Nuclear Operations, SCE&G *-1995
C. E. Zeigler 53 President and Chief Operating
Officer of PSNC 2000-present
Chairman, President and Chief
Executive Officer of PSNC *-2000
A. H. Gibbes 53 President, Pipeline Corporation 1996-present
Senior Vice President and
General Counsel *-1996
President and Treasurer,
SCANA Development Corp. *-present
K. B. Marsh 44 Senior Vice President - Finance,
Chief Financial Officer
and Controller 1998-present
Vice President - Finance,
Chief Financial Officer
and Controller 1996-1998
Vice President - Finance,
Treasurer and Secretary *-1996
H. T. Arthur 54 Senior Vice President and
General Counsel 1998-present
Vice President and General Counsel 1996-1998
Vice President and General
Counsel, Pipeline Corporation *-1996
A. M. Milligan 40 Senior Vice President - Marketing 1998-present
Director of Consumer Credit Marketing,
Barnett Bank, N. A., FL 1996-1998
Senior Vice President - Marketing,
Barnett Card Services, FL *-1996
G. J. Bullwinkel 51 Senior Vice President, Governmental
Affairs and Economic Development 1999-present
President, SCI 1997-present
Senior Vice President - Retail
Electric, SCE&G 1995-1999
* Indicates position held at least since March 1, 1995.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
COMMON STOCK INFORMATION - SCANA Corporation
- ---------------- ---------------------------- ---------------------------------------------
1999 1998
- ---------------- ----------------- --------------------------------------------- -- --------
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
- ---------------- --------- ------------------- ------------------------------------ --------
Price Range: (a)
High 28 5/16 25 11/16 26 15/16 32 9/16 37 1/4 33 7/8 31 3/8 31
Low 23 5/8 22 13/16 21 1/8 21 9/16 31 5/16 28 1/2 28 27 7/8
- ---------------- --------- ------------------- ------------------------------------ --------
(a) As reported on the New York Stockxchange Composite Listing.
Dividends Per Share:
1999 Amount Date Declared Date Paid
---- ------ ------------- ---------
First Quarter .3850 March 9, 1999 April 1, 1999
Second Quarter .3850 June 9, 1999 July 1, 1999
Third Quarter .2750 September 10, 1999 October 1, 1999
Fourth Quarter .2750 December 10, 1999 January 1, 2000
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
December 31,
-------------------------------------
1999 1998
---- ----
Number of common shares outstanding 103,572,623 103,572,623
Number of common stockholders of record 25,369 30,983
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 29,
2000 was 104,730,049. The number of common stockholders of record at February
29, 2000 was 16,215.
All of SCE&G's common stock is owned by SCANA and has no market. During
1999 and 1998 SCE&G paid $122.4 million and $167.3 million, respectively, in
cash dividends to SCANA.
SECURITIES RATINGS (As of February 29, 2000)
SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY
- -------------------------------- -------------------------------------------------------------------------------
Rating Medium-Term First Mortgage First and Refunding Preferred Trust 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 & Poors A- A A BBB+ BBB+ A-1
- -------------------------------- -------------------------------------------------------------------------------
Further reference is made to Note 5 of the Notes to Consolidated Financial
Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for
SCANA and SCE&G.
Between January 1, 1997 and December 31, 1999 67,532 shares of SCANA's no
par value common stock ("Common Stock") were purchased in open market
transactions by SunTrust Bank as Trustee of the SCANA Propane Gas, Inc. (SPG)
Profit Sharing and 401(K) Plan and Trust (the "Plan"). These shares were not
registered under the Securities Act of 1933, as amended. These shares were
purchased for the accounts of those employees of SPG and certain other
affiliates (Participating Employers) that participated in the Plan. Under the
terms of the Plan, employees could contribute up to 10 percent of their
"eligible earnings" to the Plan. For each dollar the employee contributed, the
Participating Employer matched it with 50 cents up to 4 percent of the
employee's eligible earnings. Prior to January 1, 1999 the Plan required that
the employee's eligible earnings that were matched, along with the matching
funds provided by the Participating Employers be invested in SCANA's common
stock. Beginning January 1, 1999 only the matching funds were required to be
invested in SCANA's common stock. All other contributions could be invested in a
variety of securities, including SCANA's common stock, at the employees'
discretion. The Plan was discontinued on November 10, 1999, concurrent with the
sale of substantially all of the assets of SPG. Although the matter is not free
from doubt, the Company believes that the open market purchase of shares by the
Trustee might be deemed to be an offer or sale of securities subject to the
registration requirements of the Securities Act of 1933, as amended.
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 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, 1999 approximately $29.7 million of retained earnings were
restricted by this requirement 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, 1999 1998 1997 1996 1995
- -----------------------------------------------------------------------------------------------------
(Millions of dollars, except statistics and per share
amounts)
Statement of Income Data
Operating Revenues $1,650 $1,632 $1,523 $1,513 $1,353
Operating Income 310 345 314 314 288
Other Income 22 13 38 29 8
Net Income 179 223 221 215 168
Balance Sheet Data
Utility Plant, Net $3,851 $3,787 $3,648 $3,529 $3,469
Total Assets 6,011 5,281 4,932 4,759 4,534
Capitalization:
Common equity 2,099 1,746 1,788 1,684 1,555
Preferred Stock (Not subject to
purchase or sinking fund) 106 106 106 26 26
Preferred Stock, net (Subject to
purchase or sinking fund) 11 11 12 43 46
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 50 - -
Long-term debt, net 1,563 1,623 1,566 1,581 1,589
- --------------------- -
Total Capitalization $3,829 $3,536 $3,522 $3,334 $3,216
==============================================================================================================
Common Stock Data
Weighted Average Number of Common
Shares Outstanding (Millions) 103.6 105.3 107.1 105.1 99.0
Earnings Per Weighted Average Share
of Common Stock $1.73 $2.12 $2.06 $2.05 $1.70
Dividends Declared Per Share of
Common Stock $1.32 $1.54 $1.51 $1.47 $1.44
Common Shares Outstanding (Year-End)
(Millions) 103.6 103.6 107.3 106.1 103.6
Book Value Per Share of Common Stock
(Year-End) $20.26 $16.86 $16.66 $15.86 $15.00
Number of Common Shareholders
of Record 25,369 30,983 33,395 36,178 38,231
Other Statistics
Electric:
Customers (Year-End) 523,552 517,447 503,905 493,320 484,354
Total sales (Million KWH) 21,774 21,203 18,852 18,905 17,779
Residential:
Average annual use per customer
(KWH) 14,011 14,481 13,214 14,149 13,859
Average annual rate per KWH $.0787 $.0801 $.0799 $.0785 $.0747
Generating capability - Net MW
(Year-End) 4,483 4,387 4,350 4,316 4,282
Territorial peak demand - Net MW 4,158 3,935 3,734 3,698 3,683
Regulated Gas:
Customers (Year-End) 260,362 256,957 252,701 248,681 243,523
Sales, excluding transportation
(Thousand Therm 1,012,890 1,002,952 945,289 893,170 877,728
Residential:
Average annual use per customer
(Therms) 507 521 531 639 570
Average annual rate per therm $.86 $.86 $.86 $.74 $.82
Nonregulated Gas:
Retail customers (Year-End) 430,950 78,091 - - -
Firm customer deliveries
(Thousand Therms) 229,660 4,692 - - -
Interruptible customer deliveries
(Thousand Therms) 618,551 2,167,931 - - -
SCE&G SELECTED FINANCIAL DATA
For the Years Ended December 31, 1999 1998 1997 1996 1995
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(Millions of dollars, except statistics)
Statement of Income Data
Operating Revenues $1,467 $1,451 $1,338 $1,345 $1,211
Operating Income 283 312 282 286 256
Other Income 12 13 9 4 9
Net Income 189 227 195 190 169
Earnings Available for Common Stock 182 219 186 185 163
Balance Sheet Data
Utility Plant, Net $3,500 $3,432 $3,310 $3,197 $3,158
Total Assets 4,404 4,246 4,054 3,959 3,802
Capitalization:
Common equity 1,558 1,499 1,447 1,413 1,315
Preferred Stock (Not subject
to purchase or sinking funds) 106 106 106 26 26
Preferred Stock, Net (Subject to
purchase or sinking funds) 11 11 12 43 46
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 50 - -
Long-term debt, net 1,121 1,206 1,262 1,277 1,279
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Total Capitalization $2,846 $2,872 $2,877 $2,759 $2,666
===================================================================================================================
Other Statistics
Electric:
Customers (Year-End) 523,581 517,472 503,930 493,346 484,381
Total sales (Million KWH) 21,746 21,204 18,853 18,907 17,781
Residential:
Average annual use per customer (KWH) 14,011 14,481 13,214 14,149 13,859
Average annual rate per KWH $.0787 $.0801 $.0799 $.0785 $.0747
Generating capability - Net MW (Year-End) 3,883 3,807 3,790 3,756 3,722
Territorial peak demand - Net MW 4,158 3,935 3,734 3,698 3,683
Gas:
Customers (Year-End) 260,246 256,842 252,587 248,496 242,342
Sales, excluding transportation
(Thousand Therms) 414,780 405,249 381,726 387,328 357,601
Residential:
Average annual use per customer (Therms) 507 521 531 639 570
Average annual rate per therm $.86 $.86 $.86 $.74 $.82
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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, (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) growth opportunities for the Company's regulated
and diversified subsidiaries, (7) the results of financing efforts, (8) changes
in the Company's accounting policies, (9) weather conditions in areas served by
the Company's subsidiaries, (10) performance of the telecommunications companies
in which the Company has made significant investments, (11) inflation, (12)
changes in environmental regulations and (13) 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, the NCUC, the FERC and the
SEC 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
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. To enhance its flexibility and
responsiveness to change, one of SCANA's wholly owned subsidiaries, SCANA Energy
Marketing (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, SCANA's electric and gas utility, SCE&G, has
undertaken a variety of initiatives, including the accelerated recovery of its
electric regulatory assets. SCE&G has 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 and billing system was implemented in 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 ability and
commitment to succeed in the evolving operating environment.
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 the write-off would be recorded. 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
$201 million and $64 million of regulatory assets and liabilities, respectively,
including amounts recorded for deferred income tax assets and liabilities of
approximately $131 million and $48 million, respectively, on its balance sheet
at December 31, 1999.
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 would be recorded. As of December 31,
1999, the Company's net investment in fossil/hydroelectric generation and
nuclear generation assets was $1,267.5 million and $602.3 million, respectively.
North Carolina Gas Market
On February 10, 2000 SCANA completed its acquisition of Public Service
Company of North Carolina, Inc. (PSNC) in a transaction valued at approximately
$900 million, including the assumption of debt. The transaction is being
accounted for as a purchase. PSNC will be operated as a wholly-owned subsidiary
of SCANA. As a result of the transaction, SCANA has become a registered public
utility holding company under PUHCA.
Georgia Retail Gas Market
Energy Marketing exceeded projections for acquiring customers in
Georgia's natural gas market. At December 31, 1999, Energy Marketing had
approximately 431,000 customers compared to approximately 78,000 at December 31,
1998. As a result, expenses were significantly higher than expected. For the 12
months ended December 31, 1999, Energy Marketing incurred losses (net of taxes)
of approximately $47.1 million. Startup costs were expensed as incurred. A
significant portion of those costs came from a $50 per customer promotional
sign-up offer, which expired April 15, 1999. Other significant costs were
incurred to establish local offices, call centers, and billing and collection
functions. The level of future revenues and expenditures is dependent on several
factors that cannot be reasonably predicted. These factors include Energy
Marketing's ability to retain customers and market share, the intensity of
competition as it continues to develop, the weather, the margin Energy Marketing
is able to achieve on gas sales and its ability to find industrial interruptible
customers to purchase available capacity. Energy Marketing anticipates breaking
even in Georgia for the year 2000.
Proposed Interstate Pipeline
On April 14, 1999, Pipeline Corporation, a wholly owned subsidiary of
the Company, announced plans to develop an interstate natural gas pipeline to
ensure adequate supplies to growing gas markets in South Carolina and North
Carolina. Details of the proposal are being finalized. Construction of the
project will require approval by the FERC and other federal and state agencies.
Contingent upon development of a market in North Carolina, Pipeline Corporation
plans to file its application with FERC.
LIQUIDITY AND CAPITAL RESOURCES
The Company's cash requirements arise primarily from SCE&G's operational
needs, the Company'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. SCANA'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 percent 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. The
facility began operations in March 1999. Financing for the facility of
approximately $139.8 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 $52 million from Cogen, alleging
that it incurred construction cost overruns relating to the facility, 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 December 2, 1999 an unsuccessful bidder for the purchase of the
propane gas assets of SCANA filed suit against SCANA in Circuit Court seeking
unspecified damages. The suit alleges the existence of a contract for the sale
of assets to the plaintiff and various causes of action associated with that
contract. The Company is confident in its position and intends to vigorously
defend the lawsuit. 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 paid the City $26 million over a four-year period
(1996 through 1999). As part of the environmental settlement, SCE&G 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 2000, excluding
requirements for fuel liabilities and short-term borrowings, and the actual
primary cash requirements for 1999 are as follows:
2000 1999
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(Millions of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $367 $256
Nuclear fuel expenditures 31 5
Investments 73 -
Maturing obligations, redemptions and
sinking and purchase fund
requirements 286 97
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Total $684 $431
============================================= ========== =====================
Approximately 22% of total cash requirements (after payment of dividends)
was provided from internal sources in 1999 as compared to 45% in 1998.
On February 22, 1999 the NCUC approved PSNC's application to use
expansion funds to extend natural gas service into Alexander County, North
Carolina and authorized disbursements from the fund of approximately $4 million.
Most of Alexander County lies within PSNC's franchised service territory and
does not currently have natural gas service. PSNC estimates that the project
will be completed prior to April 2000 at a cost of approximately $6.2 million.
SCANA has in effect a medium-term note program for the issuance
from time to time of unsecured medium-term debt securities. At December 31,
1999, SCANA had registered with the SEC and available for issuance $1.0 billion
under this program. The proceeds from the sales of these securities may be used
to refinance bank borrowings and other privately sold indebtedness incurred in
connection with the acquisition of PSNC. In addition, the proceeds 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.
SCE&G's First and Refunding Mortgage Bond Indenture, dated
April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance of
additional bonds thereunder (Class A Bonds) unless net earnings (as therein
defined) for 12 consecutive months out of the 18 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, 1999 the
Bond Ratio was 6.01. The Old Mortgage allows the issuance of additional Class A
Bonds to an additional principal amount equal to (i) 70 percent of unfunded net
property additions (which unfunded net property additions totaled approximately
$1,250 million at December 31, 1999), (ii) retirements of Class A Bonds (which
retirement credits totaled $91.8 million at December 31, 1999), 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 $715 million were available for such purpose at December 31,
1999). New Bonds will be issuable under the New Mortgage only if adjusted net
earnings (as therein defined) for 12 consecutive months out of the 18 months
immediately preceding the month of issuance are at least twice the annual
interest requirements on all outstanding bonds (including Class A Bonds) and New
Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1999
the New Bond Ratio was 5.95.
The following additional financing transactions have occurred since
January 1, 1999:
o On March 9, 1999 SCE&G issued $100 million of First Mortgage Bonds
having an annual interest rate of 6 1/8 percent and maturing on March
1, 2009. The proceeds from the sale of these bonds were used to
reduce short-term debt.
o On June 29, 1999 SCANA issued $150 million one-year floating rate
medium-term notes maturing on July 14, 2000. The interest rate on the
notes is reset monthly and is based on a one-month LIBOR plus 35
basis points. The proceeds from these notes were used to reduce
short-term bank debt.
o On July 15, 1999 SCANA paid at maturity all $43 million principal
amount outstanding of its 7.17 percent medium-term notes.
o On October 8, 1999 SCANA paid at maturity all $30 million principal
amount outstanding of its 6.6 percent medium-term notes.
o On November 1, 1999 SCANA's shelf registration statement filed with
the SEC became effective, providing for the issuance of up to an
additional $1 billion in medium-term notes.
o On December 1, 1999 SCANA signed a credit agreement with banks for a
maximum of $300 million for a three-year term loan, all of which was
drawn on February 10, 2000 to consummate SCANA's acquisition of PSNC.
o On February 8, 2000 SCANA issued $400 million of two-year floating
rate notes maturing February 8, 2002. The interest rate on the notes
is reset quarterly based on a three-month LIBOR plus 50 basis points.
The proceeds from these privately sold notes were used to consummate
SCANA's acquisition of PSNC.
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 percent 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 12 months or less, but not later than December 31, 2001. GENCO
has not sought such authorization.
At December 31, 1999 SCE&G had $285 million of authorized lines of
credit which include a credit agreement for a maximum of $250 million to support
the issuance of commercial paper. Unused lines of credit at December 31, 1999
totaled $285 million. SCE&G's commercial paper outstanding at December 31, 1999
and December 31, 1998 was $143.1 million and $125.2 million, respectively. In
addition, Fuel Company has a credit agreement for a maximum of $125 million with
the full amount available at December 31, 1999. 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, 1999 was $70.2 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 12 consecutive
months immediately preceding the month of issuance are at least one and one-half
times the aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended December 31, 1999 the
Preferred Stock Ratio was 1.79.
PSNC has committed lines of credit with five commercial banks which
vary monthly depending upon seasonal requirements and a five-year revolving line
of credit with one bank. These lines of credit range from a minimum of $55
million to a winter-period maximum of $75 million. PSNC also has total
uncommitted lines of credit ranging from $70 million to $100 million.
On May 21, 1999 PSNC filed with the SEC a registration statement
(amended on June 7, 1999) covering up to an aggregate of $150 million of senior
unsecured debt securities. At September 30, 1999 $150 million remained on the
shelf registration.
On May 11, 1999 SCANA registered 112,202,217 shares of SCANA common
stock for issuance to complete its acquisition of PSNC. On September 17, 1999 an
additional 4, 000,000 shares of SCANA common stock were registered for sale
under the SPSP. On September 9, 1999 an additional 3,000,000 shares of SCANA
common stock were registered for sale under the Investor Plus Plan. During 1999,
shares for the SPSP and the Investor Plus Plan were purchased on the open
market.
The Company anticipates that its 2000 cash requirements of $472 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 12 months and for the foreseeable
future.
On September 21, 1999 SCE&G announced a $180 million gas turbine
generator project in Aiken County, South Carolina. Two combined-cycle turbines
will burn natural gas to produce 300 megawatts of new electric generation and
use exhaust heat to replace coal-fired steam that powers two existing 75
megawatt turbines at the Urquhart Generating Station. The turbine project is
scheduled to be completed by June 2002.
On October 15, 1999 the FERC notified SCE&G of its agreement with
SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case
of an extreme earthquake. SCE&G and FERC have been discussing possible
reinforcement alternatives for the dam over the past several years as part of
SCE&G's ongoing hydroelectric operating license with FERC. Costs of the
alternatives being discussed range up to approximately $195 million. Although
any costs incurred by SCE&G would be recoverable through electric rates, SCE&G
also is exploring alternative sources of funding. The project is to be completed
by the end of 2003.
Environmental Matters
The Clean Air Act requires electric utilities to substantially reduce
emissions of sulfur dioxide and nitrogen oxide by the year 2000. These
requirements are being phased in over two periods. The first phase had a
compliance date of January 1, 1995 and the second, January 1, 2000. The
Company's facilities did not require modifications to meet the requirements of
Phase I. The Company is meeting 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 have
been 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 proposed in 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
1999, 1998 and 1997. The Company currently estimates that air emissions control
equipment will require capital expenditures of $141 million over the 2000-2004
period to retrofit existing facilities, with increased operation and maintenance
costs of approximately $18 million per year. To meet compliance requirements
through the year 2009, the Company anticipates total capital expenditures of
approximately $146 million.
The Federal Clean Water Act, as amended, provides for the imposition of
effluent limitations that require various levels of treatment for each
wastewater discharge. Under this Act, compliance with applicable limitations is
achieved under a national permit program. Discharge permits have been issued for
all and renewed for nearly all of SCE&G's and GENCO's generating units.
Concurrent with renewal of these permits, the permitting agency has implemented
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. Amendments to the Clean Water
Act proposed in Congress include several provisions which, if passed, could
prove costly to SCE&G and GENCO. These include, but are not limited to,
limitations to mixing zones and the implementation of technology-based
standards.
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. These regulations 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 had recovered all
amounts previously deferred for its electric operations. The Company expects to
recover all deferred amounts related to its gas operations by December 2005.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $23.7 million and $21.3 million at December 31, 1999 and
1998, 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 MGPs, 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, which cost approximately $3.5 million, included excavation and
installation of several permanent barriers to mitigate coal tar seepage. 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. SCE&G
estimates that the Record of Decision will result in costs of approximately
$13.3 million, of which approximately $4 million remains. 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. However, SCE&G
submitted a Comprehensive Remedial Design Work Plan on December 17, 1999,
and is proceeding with implementation pending agency approval.
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
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 MGP 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.
In addition, PSNC owns, or has owned, all or portions of six sites in North
Carolina on which MGPs were formerly operated. Intrusive investigation
(including drilling, sampling and analysis) has begun at only one site and the
remaining sites have been evaluated using historical records and observations of
current site conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. The North Carolina Department of
Environment and Natural Resources has recommended that no further action be
taken with respect to one site. In March and April 1994, an environmental
consulting firm retained by PSNC estimated that the aggregate cost of
investigating and monitoring the extent of environmental degradation and of
implementing remedial procedures with respect to the remaining five sites may
range from $3.7 million to $50.1 million over a 30-year period. PSNC is unable
to determine the rate at which costs may be incurred over this time period. The
estimated cost range has not been discounted to present value. The range
includes cost of investigating and monitoring the sites at the low end of the
range and investigating, monitoring and extensively remediating the sites at the
high end of the range. PSNC's associated actual costs for these sites will
depend on a number of factors, such as actual site conditions, third-party
claims and recoveries from other PRPs.
An order of the NCUC dated May 11, 1993 authorized deferral accounting for all
costs associated with the investigation and remediation of MGP sites. As of
September 30, 1999, PSNC has recorded a liability and associated regulatory
asset at the minimum amount of the range, or $3.7 million.
The NCUC concluded that it is proper and in the public interest to allow
recovery of prudently incurred clean-up costs from current customers as
reasonable operating expenses even though the MGP sites are not used and useful
in providing gas service to current customers. However, the NCUC will not allow
recovery of carrying costs on deferred amounts.
Regulatory Matters
On December 30, 1999 PSNC filed an application with the NCUC to extend
natural gas service to Madison, Jackson and Swain Counties, North Carolina. PSNC
estimates that the cost of this project will be approximately $31.4 million and
had requested the use of $30 million from its expansion fund to make this
project economically feasible. Pursuant to state statutes, the NCUC required
PSNC to forfeit its exclusive franchises to serve six counties in western North
Carolina effective January 31, 2000 because these counties were not receiving
any natural gas service. Madison, Jackson and Swain Counties were included in
the forfeiture order. PSNC has requested reassignment of the exclusive
franchises for Madison, Jackson and Swain Counties to PSNC in its request to
provide service to these counties.
On September 14, 1999 the PSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan will be implemented beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery methodology wherein SCE&G will increase depreciation of its Cope
Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of revenues and
operating expenses, not to exceed $36 million annually without the approval of
the PSC. Any unused portion of the $36 million in any given year could be
carried forward for possible use in the subsequent year. The accelerated capital
recovery plan will be accomplished through existing customer rates.
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 12 months ended September 30, 1998. This return on
common equity exceeded SCE&G's authorized return of 12 percent by 1.04 percent,
or $22.7 million, primarily as a result of record-breaking heat experienced
during the summer. The order required prospective rate reductions on a per
kilowatt-hour basis, based on actual retail sales for the 12 months ended
September 30, 1998.. 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 percent. The rate reductions were placed into
effect with the first billing cycle of January 1999.
On November 6, 1997 the NCUC issued an order permitting PSNC, on a
two-year trial basis, to establish its commodity cost of gas for large
commercial and industrial customers on the basis of market prices for natural
gas. This procedure allows PSNC to manage its deferred gas costs balance better
by ensuring that the amount paid for natural gas to serve these customers
approximates the amount collected from them. PSNC has filed an application with
the NCUC for authority to make this procedure permanent. The Carolina Utility
Customers Association, Inc. (CUCA) has intervened in opposition of its
continuance. The NCUC issued an order scheduling a hearing in February 2000 on
PSNC's application, and authorized PSNC to continue to use this mechanism
pending issuance of a final order sometime in 2000. While management cannot
predict the outcome of PSNC's application, it does not expect the decision to
have a material financial impact. PSNC will continue to establish a benchmark
cost of gas for residential and commercial/small industrial customers pursuant
to its existing procedures.
On January 9, 1996 the PSC issued an order granting SCE&G an increase in
retail electric rates which were fully implemented by January 1997. The PSC
authorized a return on common equity of 12.0 percent. 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 $9.8 million 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. After
appeals to the Circuit Court initiated by direct industrial customers and a
subsequent appeal to the Supreme Court initiated by Pipeline Corporation, the
PSC order was reinstated. The Supreme Court held that the industrial customer
group's appeal was premature and failed to exhaust administrative remedies.
Additionally, the Supreme Court interpreted the ratemaking 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. On October
10, 1997, the Circuit Court issued an order in favor of the Consumer Advocate
and the industrial customer group, which remanded the case to the PSC to
determine an overall rate of return for Pipeline Corporation and 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 held Pipeline Corporation's appeal
of the second order in abeyance until the PSC completes proceeding 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 percent. The South
Carolina Energy Users Committee (SCEUC) appealed the order to the Circuit Court.
On March 26, 1999, the Circuit Court dismissed the SCEUC's appeal on the grounds
that it was not timely filed.
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.
Other
At December 31, 1999, SCANA Communications Holdings, Inc. (SCH), a
wholly owned subsidiary of 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. SCH owns
approximately 4.9 million common shares of Powertel at a cost of
approximately $72.8 million. Powertel common stock closed at $100.375 per
share on December 31, 1999, resulting in a pre-tax unrealized holding gain
of $417.8 million. The after-tax amount of such gain is included in "Other
Comprehensive Income." In addition, SCH 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). Dividends on
Preferred series E shares are paid in common shares of Powertel. 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, as converted, the market
value of the underlying common shares for the preferred shares was
approximately $975.3 million at December 31, 1999, resulting in an
unrecorded pre-tax holding gain of $802.7 million.
o ITC^DeltaCom, Inc. (ITCD) is a fiber optic telecommunications provider. SCH
owns approximately 5.1 million common shares of ITCD at a cost of
approximately $42.7 million. ITCD common stock closed at $27.625 per share
on December 31, 1999, resulting in a pre-tax unrealized holding gain of
$98.3 million. The after-tax amount of such gain is included in "Other
Comprehensive Income." In addition, SCH 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. The market value of series A preferred stock of ITCD is
not readily determinable. However, as converted, the market value of the
underlying common stock for the series A preferred stock was approximately
$81.8 million at December 31, 1999, resulting in an unrecorded pre-tax
holding gain of $70.6 million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of cable
television, telephone and internet services. SCH owns 71,050 units of
Knology. Each unit consists of one 11.875 percent 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. In addition, in November 1999, SCH exercised 753 warrants to
purchase 753 series A preferred shares of Knology at a cost of $1.1
million. Immediately following this purchase, Knology preferred shares
split 600 for one, resulting in SCH's ownership of 451,800 shares. The
market value of this investment is not readily determinable.
o ITC has an ownership interest in several Southeastern communications
companies. SCH owns approximately 3.1 million common shares, 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 on a four to
one basis. The market value of these investments is not readily
determinable.
The Company successfully completed its efforts to ensure Year 2000
readiness for all of its critical systems. As a result, the Company experienced
no interruption in the services it provides to its customers during the
transition to the Year 2000. Although the Company has not experienced any Year
2000 problems, there can be no guarantees that there will not be any Year 2000
problems in the future. The cost of the Company's Year 2000 efforts totaled
approximately $16.3 million.
On November 10, 1999 substantially all of the assets of SCANA Propane
Gas, Inc., SCANA Propane Storage, Inc., and C&T Pipeline, LLC were sold for
approximately $94.5 million. The resulting after-tax gain of $29.9 million was
recorded in "Other Income." Proceeds from the sale were used to reduce
short-term debt.
On December 1, 1997, SCANA 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." Proceeds from the sale were used during 1998 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.
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 1999 through 1997 were as follows:
1999 1998 1997
----------------------------------------------------- ------------------------
Earnings derived from:
Continuing operations $1.39 $2.07 $1.90
Non-recurring gains .34 .05 .16
------- ------- -------
Earnings per weighted average share $1.73 $2.12 $2.06
===== ===== =====
Return earned on common equity 8.5% 12.8% 12.3%
----------------------------------------------------- ------------------------
o 1999 Earnings derived from continuing operations decreased $.68,
primarily as a result of losses from the Company's entry into the
Georgia retail gas market ($.37 greater loss in 1999). In addition,
electric margin decreased $.12 (see discussion at Electric
Operations), gas margin decreased $.04, and expenses were higher for
other operations and maintenance ($.04), depreciation and
amortization ($.09) and interest expense ($.11). These decreases
were partially offset by improved results from energy marketing
activities ($.04, non-Georgia), the impact of fewer common shares
outstanding ($.03), and other ($.02).
o 1998 Earnings derived from continuing operations increased $.17,
primarily as a result of increased electric margin ($.47; see
discussion at Electric Operations), an increase in gas margin
($.05), the impact of fewer common shares outstanding ($.03), and
lower preferred stock dividends ($.02). These increases were
partially offset by increased Other operation and maintenance
($.18), expenses from the Company's entry into the Georgia retail
gas market ($.08), lower margins from energy marketing activities
($.05, non-Georgia), higher interest expense ($.03), higher property
taxes ($.03), higher depreciation and amortization expense ($.01),
and other ($.02).
Pension income recorded by the Company reduced operations expense by $17.3
million, $16.9 million and $12.2 million for the years ended December 31, 1999,
1998 and 1997, respectively. In addition, pension income increased other income
by $10.5 million and $9.0 million for the years ended December 31, 1999 and
1998, respectively. The reductions to operations expense for 1998 and 1997 were
substantially offset by accelerated amortizations of a significant portion of
the transition obligation for postretirement benefits other than pensions and
certain regulatory assets as approved by the PSC.
Non-recurring gains resulted from the sale of retail propane assets ($.29)
and telecommunications towers ($.05) in 1999, a retroactive change in electric
depreciation rates ($.05) in 1998, and the sale of oil and natural gas
production assets ($.16) in 1997.
Return on common equity decreased in 1999 primarily due to decreased
earnings. In addition, common equity increased in 1999 due to a $311 million
unrealized gain on the Company's investments in telecommunications securities.
The increase in common equity, without a proportional increase in net income,
decreased the return earned on common equity by 1.6%.
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 2.4 percent of
income before income taxes in 1999, 4.4 percent in 1998 and 4.0 percent in 1997.
On February 17, 1999, the Board of Directors adopted a new common stock
dividend policy to bring the Company's dividend payout ratio more in line with
that of growth-oriented utilities. The board's action makes the Company's
indicated annual dividend rate on common stock $1.10 per share.
On November 10, 1999, substantially all of the retail propane assets of
the Company were sold for approximately $94.5 million. The resulting after-tax
gain of $29.9 million was recorded in "Other Income."
Electric Operations
Electric operations sales margins for 1999, 1998 and 1997 were as
follows:
1999 1998 1997
- ---------------------------------- ------------- ------------- -------------
(Millions of
Dollars)
Operating revenues $1,226.0 $1,219.8 $1,103.0
Less: Fuel used in generation
284.6 262.3 248.4
Purchased power
35.9 31.5 9.4
- ---------------------------------- ------------- ------------- -------------
Margin $ 905.5 $ 926.0 $ 845.2
================================== ============= ============= =============
o 1999 The sales margin decreased primarily due to the impact of a rate
reduction at SCE&G and milder weather, which was partially offset
by customer growth.
o 1998 The sales margin increased for 1998 primarily due to more favorable
weather and customer growth.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes were as follows:
Classification 1999 % Change 1998 % Change
- -------------------------------------------------------------------------- -----
Residential (55,207) (0.9%) 676,578 12.0%
Commercial 51,212 0.9% 578,290 10.9%
Industrial 316,086 5.4% 389,931 7.2%
Sales for Resale (excluding interchange) 63,306 5.6% 65,367 6.2%
Other (17,653) (3.3%) 29,823 5.9%
- ------------------------------------------------------------------------------ -
Total territorial 357,744 1.8% 1,739,989 9.7%
Negotiated Market Sales Tariff 183,442 12.3% 610,784 69.1%
============================================================================== =
Total 541,186 2.6% 2,350,773 12.5%
============================================================================== =
o 1999 The sales volume decrease for residential was primarily due to
milder weather which was partially offset by customer growth.
Volumes for the remaining classes increased primarily due to
customer growth.
o 1998 The sales volume increases for 1998 were primarily due to more
favorable weather and customer growth.
Gas Distribution
Gas distribution sales margins for 1999, 1998 and 1997 were as follows:
1999 1998 1997
- --------------------------------------------- ------------- -------------
(Millions of
Dollars)
Operating revenues $ 239.0 $ 230.4 $ 233.6
Less: Gas purchased for resale 152.6 142.4 151.9
Margin $ 86.4 $ 88.0 $ 81.7
============================================= ============= =============
o 1999 The sales margin decreased for 1999 primarily as a result of higher
gas costs.
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.
Increases (decreases) from the prior year in dekatherm (DT) sales volume
by classes, including transportation gas, were as follows:
Classification 1999 % Change 1998 % Change
- ---------------------------------- --------------- --------------------------
Residential (94,027) (0.8%) 0.0%
(2,685)
Commercial 404,654 3.6% 3.6%
389,468
Industrial 644,485 3.7% 1,965,506 12.8%
Transportation gas (28,732) (1.4%) (25.2%)
(673,795)
Total 926,380 2.2% 1,678,494 4.1%
================================== =============== ==========================
o 1999The sales volume increased for 1999 primarily as a result of
customer expansion and customer growth. Residential volume
decreased primarily due to milder weather.
o 1998 The sales volume for commercial and industrial customers increased
for 1998 as a result of lower gas prices and increased sales to
electric generation facilities.
Gas Transmission
Gas transmission sales margins for 1999, 1998 and 1997 were as follows:
1999 1998 1997
- --------------------------------------------- ------------- -------------
(Millions of
Dollars)
Operating revenues $342.4 $329.8 $339.9
Less: Gas purchased for resale 295.1 276.7 289.3
Margin $ 47.3 $ 53.1 $ 50.6
============================================= ============= =============
o 1999 The sales margin decreased from 1998 primarily as a result of
increased competition with oil prices and a decrease in the value
of released capacity on the interstate pipeline system.
o 1998 The sales margin increased over 1997 primarily as a result of
increased sales to electric generation facilities.
Increases (decreases) from the prior year in dekatherms (DT) sales volume
by classes including transportation gas were as follows:
Classification 1999 % Change 1998 % Change
--------------------------------------------------------- ------------
Commercial 200 0.2% 9,799 12.0%
Industrial (916,235) (2.0%) 5,238,940 13.0%
Transportation (179,029) (7.4%) (695,921) (22.3%)
Sale for resale 2,122,252 3.8% 314,895 0.6%
========================================================= ============
Total 1,027,188 1.0% 4,867,713 4.9%
========================================================= ============
o 1999The sales volumes for sale for resale customers increased for
1999 as a result of customer growth and customer expansion on our
sale for resale customers' systems. Transportation volumes
decreased due to improved results from gas marketing efforts.
These improved results were more than offset by increased
competition with oil prices, which resulted in an overall decrease
in industrial volumes.
o 1998The sales volume for commercial and industrial customers
increased for 1998 as a result of lower gas prices and increased
sales to electric generation facilities. Transportation volumes
decreased due to improved results from gas marketing efforts.
Energy Marketing
Energy marketing sales margins for 1999, 1998 and 1997 were as follows:
1999 1998 1997
--------------------------------------------------------------
(Millions of Dollars)
Operating revenue $429.9 $568.1 $205.9
Less: Gas and electricity
purchased for resale 432.1 569.8 203.3
--------------------------------------------------- -----------
Margin $(2.2) $(1.7) $ 2.6
=================================================== ===========
o 1999 The sales margin decreased in 1999 primarily due to intense
competition in the Georgia retail natural gas market.
o 1998 The sales margin decreased for 1998 primarily due to losses on
energy trading, intense competition related to Energy Marketing's
entry into the Georgia retail natural gas market, and continued
mild weather.
Delivered volumes for 1999 totaled approximately 84,821,175 DT, which
included firm customer volumes of 22,966,029 DT and interruptible customer
volumes of 61,855,146 DT. Approximately 27.1 percent of total delivered volumes
were for residential and commercial customers in Georgia. Total volumes
decreased from 1998 primarily due to closure of the Houston wholesale trading
office.
Delivered volumes for 1998 totaled approximately 217,262,286 DT, which
included firm customer volumes of 469,189 DT and interruptible customer volumes
of 216,793,097 DT.
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including taxes, were as
follows:
1999 % Change 1998 % Change
- -----------------------------------------------------------------------------
(Millions of Dollars)
Other operation and maintenance $6.9 2.0% $31.1 10.0%
Depreciation and amortization 23.4 16.1% (8.2) (5.4%)
Income taxes (25.6) (18.8%) 30.8 29.2%
Other taxes 1.9 1.9% 5.7 5.9%
============================================================================
Total 6.6 0.9% $59.4 8.9%
============================================================================
o 1999 Other operation and maintenance increased primarily due to costs
associated with a cogeneration facility becoming operational, costs
associated with an early retirement program and other operating costs.
These costs were partially offset by pension income, which in 1998 had
been offset by the accelerated amortization of the electric portion of
the Company's transition obligation expense for post-retirement
benefits and other regulatory assets. Depreciation and amortization
increased primarily due to the impact of the non-recurring adjustment
to depreciation expense discussed under earnings and dividends,
increased amortization due to completion of a new customer billing
system, and normal increases in utility plant. Income taxes decreased
primarily due to decreased operating income. Other taxes increased
primarily due to increased property taxes.
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.
Other Income
o 1999Other income, net of taxes, increased approximately $9.1
million, primarily as a result of the gain on the sale of
non-regulated propane assets and telecommunications towers, which
was partially offset by increased losses from retail gas marketing
activities.
o 1998 Other 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. The impact of these
items was partially offset by pension income recorded in 1998.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
1999 1998
- ----------------------------------------------------------------------
(Millions of Dollars)
Interest on long-term debt, net $11.4 $5.4
Other interest expense 3.9 (1.8)
- ----------------------------------------------- ---------------------
Total $15.3 $3.6
=============================================== =====================
o 1999 Interest expense increased over 1998 as a result of increased
long-term debt and increased weighted average interest rates on
long-term and short-term borrowings.
o 1998 Interest expense increased over 1997 as a result of the issuance
of medium-term notes in 1998 to finance nonregulated activities.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations, the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
December 31, 1999 Expected Maturity Date
------------------------------------------------------
(Millions of Dollars)
Liabilities 2000 2001 2002 2003 2001 Thereafter Total Fair Value
------------------------ --------------- -------------
Long-Term Debt:
Fixed Rate ($) (1) 152.5 32.5 32.5 289.3 178.8 1,150.3 1,836.1 1,680.7
Average Fixed Interest
Rate 6.85 6.85 6.17 7.50 7.33 6.20 7.05
Variable Rate ($) 150.0 150.0 150.0
Average Variable Interest
Rate 6.45
December 31, 1998 Expected Maturity Date
----------------------------------------------------------
(Millions of Dollars)
Liabilities 2000 2001 2002 2003 2001 Thereafter Total Fair Value
------ ---------------------------------------------------
Long-Term Debt:
Fixed Rate ($) 106.7 213.5 27.5 27.5 284.4 1,165.8 1,825.4 1869.2
Average Interest Rate 6.86 6.86 6.29 7.48 6.86 5.95 7.06
(1) There were no debt issuances outstanding under the December 1, 1999
credit agreement for $300 million.
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 percent 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.
Commodity price risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.
December 31, 1999 Expected Maturity in 2000
Weighted Avg Contract Fair
Natural Gas Derivatives: Settlement Price Amount Value
- --------------------------------------------------- ------------- -------------
(Millions of Dollars)
Future Contracts:
Long $2.3318 $20.0 $19.8
Short $2.3290 $ 1.2 $ 1.1
SET Futures Contracts (1):
Long $2.7161 $ 5.0 $ 5.1
Short $2.7461 $ 4.7 $ 4.8
December 31, 1998 Expected Maturity in 2000
Weighted Avg Contract Fair
Natural Gas Derivatives: Settlement Price Amount Value
- -------------------------------- ------------------ ------------- -------------
(Millions of Dollars)
Future Contracts:
Long $2.3850 $1.9 $1.8
Short $ - $ - $ -
SET Futures Contracts (1):
None
December 31, 1998 Expected Maturity in 1999
Weighted Avg Contract Fair
Natural Gas Derivatives: Settlement Price Amount Value
- -------------------------------- ------------------ ------------- -------------
(Millions of Dollars)
Future Contracts:
Long $2.0032 $13.0 $12.2
Short $1.9417 $ 0.8 $ 0.8
SET Futures Contracts (1):
None
(1) SCANA Energy Trading, LLC (SET) is a 70% owned subsidiary of SCANA
Energy Marketing, Inc. Amounts shown are at 100%.
Equity price risk - Investments in telecommunications companies' marketable
equity securities are carried at the lower of their cost or market value of
which totaled $889.1 million, in accordance with Statement of Financial
Accounting Standards No. 115. A ten percent decline in market value would result
in a $88.9 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............................................ 42
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1999 and 1998............. 43
Consolidated Statements of Income and Retained Earnings
for the years ended December 31, 1999, 1998 and 1997............... 45
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997................................... 46
Consolidated Statements of Capitalization as of December 31,
1999 and 1998...................................................... 47
Consolidated Statements of Changes in Common Equity for the years
ended December 31, 1999, 1998 and 1997.............................. 49
Notes to Consolidated Financial Statements.............................. 50
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 and Statements
of Capitalization of SCANA Corporation (Company) as of December 31, 1999 and
1998 and the related Consolidated Statements of Income and Retained Earnings,
Changes in Common Equity and of Cash Flows for each of the three years in the
period ended December 31, 1999. Our audits also included the financial satement
schedule listed in Part IV at Item 14. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule 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,
1999 and 1998 and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1999 in conformity with
generally accepted accounting principles. Also, in our opinion, such financial
statement schedule, when considered taken as a whole, presents fairly in all
material aspects the information set forth therein.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 10, 2000
SCANA Corporation
CONSOLIDATED BALANCE SHEETS
December 31, 1999 1998
ASSETS (Millions of Dollars)
Utility Plant (Notes 1, 3 & 4):
Electric $4,633 $4,406
Gas 632 604
Other 191 175
- --------------------------------------------------------------------------------
Total 5,456 5,185
Less accumulated depreciation and amortization 1,829 1,728
- --------------------------------------------------------------------------------
Total 3,627 3,457
Construction work in progress 159 251
Nuclear fuel, net of accumulated amortization 43 56
Acquisition adjustment-gas, net of accumulated amortization 22 23
- --------------------------------------------------------------------------------
Utility Plant, Net 3,851 3,787
- --------------------------------------------------------------------------------
Nonutility Property and Investments (net of accumulated
depreciation)(Note 1) 999 493
- --------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments (Note 8) 116 62
Receivables 320 276
Inventories (At average cost):
Fuel (Notes 3 & 4) 55 63
Materials and supplies 78 56
Prepayments 27 22
Deferred income taxes (Note 7) 16 22
- --------------------------------------------------------------------------------
Total Current Assets 612 501
- --------------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 24 22
Nuclear plant decommissioning fund (Note 1) 64 56
Pension asset, net (Note 1) 144 115
Other regulatory assets 177 194
Other (Notes 1 & 10) 109 82
- ------------------------------------------------------------------------------
Total Deferred Debits 549 500
- --------------------------------------------------------------------------------
Total $6,011 $5,281
================================================================================
December 31, 1999 1998
CAPITALIZATION AND LIABILITIES (Millions of Dollars)
Stockholders' Investment:
Common Equity (Note 5) $2,099 $1,746
Preferred stock (Not subject to purchase or sinking funds) 106 106
- --------------------------------------------------------------------------------
Total Stockholders' Investment 2,205 1,852
Preferred Stock, net (Subject to purchase or sinking
funds)(Notes 6 & 8) 11 11
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
(Note 6) 50 50
Long-Term Debt, net (Notes 3 & 8) 1,563 1,623
- -------------------------------------------------------------------------------
Total Capitalization 3,829 3,536
- --------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings (Notes 4, 8 & 9) 266 195
Current portion of long-term debt (Note 3) 303 107
Accounts payable 189 219
Customer deposits 16 18
Taxes accrued 86 72
Interest accrued 29 28
Dividends declared 31 42
Other 13 13
- --------------------------------------------------------------------------------
Total Current Liabilities 933 694
- --------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes (Notes 1 & 7) 805 628
Deferred investment tax credits (Notes 1 & 7) 116 108
Reserve for nuclear plant decommissioning (Note 1) 64 56
Postretirement benefits (Note 1) 98 87
Other regulatory liabilities 64 71
Other (Note 1) 102 101
- --------------------------------------------------------------------------------
Total Deferred Credits 1,249 1,051
- --------------------------------------------------------------------------------
Commitments and Contingencies (Note 10) - -
- --------------------------------------------------------------------------------
Total $6,011 $5,281
================================================================================
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------
(Millions of Dollars
except per share amounts)
Operating Revenues (Notes 1 & 2):
Electric $1,226 $1,220 $1,103
Gas 422 411 419
Transit 2 1 1
- ------------------------------------------------------------------------------------------
Total Operating Revenues 1,650 1,632 1,523
- ------------------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 285 262 248
Purchased power 36 31 9
Gas purchased for resale 289 269 287
Other operation (Note 1) 258 257 239
Maintenance (Note 1) 90 84 72
Depreciation and amortization (Note 1) 168 145 153
Income taxes (Notes 1 & 7) 110 136 105
Other taxes 104 103 96
- ------------------------------------------------------------------------------------------
Total Operating Expenses 1,340 1,287 1,209
- ------------------------------------------------------------------------------------------
Operating Income 310 345 314
- ------------------------------------------------------------------------------------------
Other Income (Note 1):
Other income(loss), net of income taxes (20) 5 13
Gain on sale of subsidiary assets, net of income taxes 39 - 18
Allowance for equity funds used during construction 3 8 7
- ------------------------------------------------------------------------------------------
Total Other Income 22 13 38
- ------------------------------------------------------------------------------------------
Income Before Interest Charges
and Preferred Stock Dividends 332 358 352
- ------------------------------------------------------------------------------------------
Interest Charges (Credits):
Interest on long-term debt, net 132 121 115
Other interest expense 14 10 12
Allowance for borrowed funds used
during construction (Note 1) (4) (8) (6)
- ------------------------------------------------------------------------------------------
Total Interest Charges, Net 142 123 121
- ------------------------------------------------------------------------------------------
Income Before Preferred Dividend Requirements
on Mandatorily Redeemable Preferred Securities 190 235 231
Preferred Dividend Requirement of SCE&G
-Obligated Mandatorily Redeemable
Preferred Securities 4 4 1
- ------------------------------------------------------------------------------------------
Income Before Preferred Stock Cash
Dividends of Subsidiary 186 231 230
Preferred Stock Cash Dividends of
Subsidiary (At stated rates) 7 8 9
- ------------------------------------------------------------------------------------------
Net Income 179 223 221
Retained Earnings at Beginning of Year 678 617 558
Common Stock Cash Dividends Declared (Note 5) (137) (162) (162)
- ------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 720 $ 678 $ 617
==========================================================================================
Net Income $ 179 $ 223 $ 221
Weighted Average Number of Common Shares
Outstanding (Millions) 103.6 105.3 107.1
Earnings Per Weighted Average Share of
Common Stock (Basic and Diluted) $1.73 $2.12 $2.06
==========================================================================================
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $179 $223 $221
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization 177 152 176
Amortization of nuclear fuel 18 20 19
Deferred income taxes, net 19 15 30
Pension asset (29) (33) (24)
Postretirement benefits 11 26 24
Other regulatory assets 23 16 37
Other regulatory liabilities (7) 4 4
Allowance for funds used during construction (7) (16) (13)
Over (under) collection, fuel adjustment clause (6) 1 -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (44) (28) 1
(Increase) decrease in inventories (14) (16) 15
Increase (decrease) in accounts payable (30) 88 (26)
Increase (decrease) in taxes accrued 14 13 (12)
Other, net (80) 2 (40)
- ----------------------------------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 224 467 412
- ---------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures,
net of AFC (238) (281) (250)
(Increase) decrease in nonutility property and investments:
Sale of subsidiary assets 112 - 118
Nonutility property (23) (22) (38)
Investments (73) (106) (75)
Net Cash Used For Investing Activities (222) (409) (245)
- ----------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of SCE&G-obligated mandatorily redeemable
trust preferred securities - - 49
Issuance of First Mortgage Bonds 99 - -
Issuance of common stock - - 29
Issuance of notes and loans 200 249 86
Issuance of preferred stock - - 99
Repayments and repurchases:
Mortgage bonds (10) (50) (15)
Notes and loans (77) (96) (70)
Other long-term debt (10) - (8)
Preferred stock - (1) (53)
Common stock - (110) -
Dividend payments:
Common stock (148) (163) (160)
Preferred stock (7) (7) (9)
Short-term borrowings, net 71 136 (86)
Fuel financings, net (66) (14) 14
- ---------------------------------------------------------------------------------------------------------
Net Cash Provided From (Used For) Financing Activities 52 (56) (124)
- ----------------------------------------------------------------------------------------------------------
Net Increase in Cash and Temporary Cash Investments 54 2 43
Cash and Temporary Cash Investments, January 1 62 60 17
- ---------------------------------------------------------------------------------------------------------
Cash and Temporary Cash Investments, December 31 $116 $ 62 $ 60
=========================================================================================================
Supplemental Cash Flow Information:
Cash paid for - Interest (Includes capitalized interest of
$4, $7 and $6) $142 $127 $124
- Income taxes 84 114 113
Noncash Financing Activities:
Unrealized gain on securities
available for sale (net of tax) 311 7 18
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1999 1998
Common Equity (Note 5): (Millions of Dollars)
Common stock, without par value, authorized 150,000,000 shares; issued
and outstanding, 103,572,623 shares in 1999 and 1998 $1,043 $1,043
Unrealized gain on securities available for sale 336 25
Retained earnings 720 678
- ------------------------------------------------------------------------------------------------------
Total Common Equity 2,099 55% 1,746 50%
- ------------------------------------------------------------------------------------------------------------
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 1999 1998
$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 and
8):
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 1999 and 1998
$50 Par Value - Authorized 1,571,487 shares
Shares Outstanding Redemption Price
Series 1999 1998
4.50% 11,200 12,800 51.00 1 1
4.60%(A) 18,052 20,052 51.00 1 1
4.60%(B) 61,200 64,600 50.50 3 3
5.125% 68,000 69,000 51.00 3 3
6.00% 73,035 73,600 50.50 4 4
-------------------
Total 231,487 240,052
===================
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1999 and 1998
Total Preferred Stock (Subject to purchase or sinking funds) 12 12
Less: Current portion, including sinking fund requirements 1 1
- ------------------------------------------------------------------------------------------------------
Total Preferred Stock, Net (Subject to purchase or sinking funds) 11 11
- ------------------------------------------------------------------------------------------------------
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%
- -----------------------------------------------------------------------------------------------------------
S>
December 31, 1999 1998
- ---------------------------------------------------------------------------------------------
Long-Term Debt (Notes 3, 4 & 8): (Millions of Dollars)
SCANA Corporation:
Medium-Term Notes:
Year of
Series Maturity
7.17% 1999 - 43
6.60% 1999 - 30
5.52% 2000 150 -
6.15% 2000 20 20
6.51% 2003 20 20
6.05% 2003 60 60
6.25% 2003 75 75
7.44% 2004 50 -
6.90% 2007 25 25
5.81% 2008 115 115
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
6 1/8% 2009 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
9% 2006 131 131
8 7/8% 2021 103 114
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 17 16
Charleston Franchise Agreement due 1997-2002 11 14
Charleston Environmental Agreement - 6
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 49 53
South Carolina Fuel Company, Inc. Commercial Paper - 66
South Carolina Pipeline Corporation Notes, 6.72%, due 2013 17 19
Other 3 3
- ---------------------------------------------------------------------------------------------
Total Long-Term Debt 1,869 1,733
Less - Current maturities, including sinking
fund requirements 303 107
- Unamortized discount 3 3
- ---------------------------------------------------------------------------------------------
Total Long-Term Debt, Net 1,563 41% 1,623 46%
- --------------------------------------------------------------------------------------------
Total Capitalization $3,829 100% $3,536 100%
============================================================================================
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the years Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------
(Millions of Dollars)
Retained Earnings:
Balance at January 1 $ 678 $ 617 $ 558
Net Income 179 $179 223 $223 221 $221
Dividends declared on common stock (137) (162) (162)
----- ------ ------
Balance at December 31 720 678 617
------ ------ ------
Accumulated other comprehensive income:
Balance at January 1 25 18 -
Unrealized gains on securities, net
of taxes ($165, $4 and $11 in 1999,
1998 and 1997, respectively) 311 311 7 7 18 18
------ ----- ------ ---- ------ -----
Comprehensive income $490 $230 $239
==== ==== =====
Balance at December 31 336 25 18
------ ------ ------
Common Stock:
Balance at January 1 1,043 1,153 1,125
Shares issued - - 28
Shares repurchased - (110) -
------ ------ ------
Balance at December 31 1,043 1,043 1,153
------ ------ -------
Total Common Equity $2,099 $1,746 $1,788
====== ====== ======
Accumulated other comprehensive income at December 31, 1999,1998 and 1997 was
comprised of unrealized holding gains on securities, net of taxes. There were no
realized gains or losses from these securities for the years ended December 31,
1999, 1998 and 1997.
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 (PUHCA) but is exempt from registration under such Act (see Note
13). 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. 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.
SCANA Communications, Inc. (SCI)
ServiceCare, Inc.
Primesouth, Inc.
SCANA Resources, Inc.
SCANA Propane Gas, Inc. (in liquidation)
SCANA Propane Services, Inc. (in liquidation)
SCANA Petroleum Resources, Inc. (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, 1999, approximately $201 million and $64 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $131 million and $48
million, respectively. The electric and gas regulatory assets of approximately
$35 million and $34 million, respectively (excluding deferred income tax
assets), are being recovered through rates and, as discussed in Note 2C, the
Public Service Commission of South Carolina (PSC) has approved accelerated
recovery of approximately $7 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 the write-off would be 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'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
$959.7 million and $983.3 million as of December 31, 1999 and 1998,
respectively. Accumulated depreciation associated with SCE&G's share of Summer
Station was approximately $365.1 million and $369.2 million as of December 31,
1999 and 1998, 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 8.1%, 8.7% and 9.1% for 1999, 1998 and 1997, 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. SCE&G and Pipeline Corporation record base revenue 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 $10.1 million and $3.1 million at
December 31, 1999 and December 31, 1998, 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, 1999 and 1998 the Company had
undercollected through the gas cost recovery procedure approximately $4.1
million and $5.2 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:
- ---------------------------------- -------------- ---------------
1999 1998 1997
- ---------------------------------- -------------- ---------------
SCE&G 2.99% 3.02% 3.09%
GENCO 2.56% 2.65% 2.63%
Pipeline Corporation 2.62% 2.63% 2.62%
Aggregate of Above 2.95% 2.98% 3.05%
- ---------------------------------- -------------- ---------------
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 are estimated, in 2022 dollars assuming a 4.5 percent annual rate of
inflation, to be $545.3 million including partial reclamation costs. SCE&G is
providing for its share of estimated decommissioning costs of Summer Station
over the life of Summer Station. SCE&G's method of funding decommissioning costs
is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds
collected through rates ($3.2 million in each of 1999 and 1998) 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 $3.2 million at December 31, 1999, 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
all significant 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 and Other Postretirement Benefits
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 expensed
approximately $0.7 million, $15.7 million and $15.6 million for the years ended
December 31, 1999, 1998 and 1997, respectively. (See Note 2C.)
Disclosures 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
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
(Millions of Dollars) (Millions of Dollars)
Service Cost $10.0 $ 8.3 $ 6.8 $3.0 $2.6 $2.5
Interest Cost 27.9 25.9 23.5 9.5 9.4 7.8
Expected return on assets (65.5) ( 59.3) (41.6) N/A N/A N/A
Prior service cost amortization 1.1 1.1 1.1 0.7 0.7 0.7
Actuarial (gain) loss (8.6) (9.6) (7.0) 1.2 1.0 0.1
Transition amount amortization 0.8 0.8 0.8 1.7 19.1 18.9
Special termination benefit cost 5.5 0.0 0.0 1.0 0.0 0.0
Net periodic benefit (income) ----- ----- ---- ----- ----- -----
cost $(28.8) $(32.8) $(16.4) $17.1 $32.8 $30.0
====== ====== ====== ===== ===== =====
Weighted-Average Assumptions as of December 31
Other
Retirement Benefits Postretirement Benefits
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
Discount rate 8.0% 7.0% 7.5% 8.0% 7.0% 7.5%
Expected return on plan assets 9.5% 9.5% 8.0% NA NA NA
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Change in Benefit Obligation
Other
Retirement Benefits Postretirement Benefits
1999 1998 1999 1998
(Millions of Dollars) (Millions of Dollars)
Benefit obligation, Jan. 1 $389.3 $344.3 137.0 $108.8
Service cost 10.0 8.3 3.0 2.6
Interest cost 27.9 25.9 9.5 9.4
Plan participants' contributions 0.1 0.2 0.5 0.5
Actuarial loss/(gain) (51.6) 28.3 (14.5) 23.3
Benefits paid (18.9) (17.7) (6.7) (7.6)
Special termination benefit cost 5.5 0.0 1.0 0.0
------ ------ ------ ------
Benefit obligation, Dec. 31 $362.3 $389.3 $129.8 $137.0
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
1999 1998
(Millions of Dollars)
Fair value of plan assets, Jan. 1 $698.8 $632.9
Actual return on plan assets 103.0 83.5
Company contribution 0.0 0.0
Plan participants' contributions 0.1 0.1
Benefits paid (18.9) (17.7)
------ ------
Fair value of plan assets, Dec. 31 $783.0 $698.8
====== ======
The Company does not fund postretirement benefits other than pensions.
Funded Status of Plans
Other
Retirement Benefits Postretirement Benefits
1999 1998 1999 1998
(Millions of Dollars) (Millions of Dollars)
Funded status, Dec. 31 $420.8 $309.5 $(129.8) $(137.0)
Unrecognized actuarial (gain)/loss (294.0) (213.4) 18.8 34.5
Unrecognized prior service cost 11.3 12.3 4.3 5.1
Unrecognized net transition
obligation 5.6 6.5 9.1 10.7
------ ------ ------- -------
Net amount recognized in
Consolidated Balance Sheets $ 43.7 $114.9 $ (97.6) $ (86.7)
====== ====== ======= =======
Health Care Trends
The determination of net periodic postretirement benefit cost is based on the
following assumptions:
1999 1998 1997
- -------------------------------------------------- ---------- ----------
Health care cost trend rate 8.0% 8.5% 9.0%
Ultimate health care cost trend rate 5.5% 5.0% 5.5%
Year achieved 2005 2005 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 $(0.2)
Effect on postretirement obligation 2.9 (3.3)
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium, discount and expense are being amortized as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues. Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.
L. Environmental
The Company has an environmental assessment program to identify and
assess current and former operations sites that could require environmental
cleanup. As site assessments are initiated, 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, 1999 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 2005.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $23.7 million and $21.3 million at December 31, 1999 and
1998, 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, SCANA Petroleum Resources, Inc.,
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
year ended December 31, 1997.
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. Commodity Derivatives
To minimize price risk due to market fluctuations, the Company utilizes
forward contracts, futures contracts, option contracts and swap agreements to
hedge certain purchases and sales of natural gas. For such transactions related
to the Company's regulated operations, gains and losses on these contracts are
included as a component of the related cost of gas which is subject to recovery
under the fuel adjustment clause. (See Note 1F). The resulting under or over
recovery of such costs is recorded in "Deferred Debits" or "Deferred Credits,"
respectively, on the balance sheet. Changes in the market value of contracts
pertaining to nonregulated operations are deferred and included in income in the
period in which the related transactions close.
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, 2001, 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 1999 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 September 14, 1999 the PSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan was implemented beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery methodology wherein SCE&G will increase depreciation of its Cope
Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of revenues and
operating expenses, not to exceed $36 million annually without the approval of
the PSC. Any unused portion of the $36 million in any given year could be
carried forward for possible use in the subsequent year. The accelerated capital
recovery plan will be accomplished through existing customer rates.
B. 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 12 months ended September 30, 1998. This return on
common equity exceeded SCE&G'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 required prospective rate reductions on a per kilowatt-hour
basis, based on actual retail sales for the 12 months ended September 30, 1998.
On January 12, 1999 the PSC denied SCE&G's motion for reconsideration. However,
the PSC also ruled that no further rate action was required, and reaffirmed
SCE&G's return on equity of 12 percent. The rate reductions were placed into
effect with the first billing cycle of January 1999.
C. On January 9, 1996 the PSC issued an order granting SCE&G an increase
in retail electric rates which were fully implemented by January 1997. The PSC
authorized a return on common equity of 12.0 percent. 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 $9.8 million 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.
D. 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 (MGPs). 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 1999, as a result of the annual review, the PSC
approved SCE&G's request to maintain the billing surcharge at $.011 per therm to
provide for the recovery of the remaining balance of $24.2 million.
E. 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.
F. 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 percent. The South Carolina Energy Users Committee
(SCEUC) appealed the order to the Circuit Court. On March 26, 1999, the Circuit
Court dismissed the SCEUC's appeal on the grounds that it was not timely filed.
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2000 through 2004 are summarized as follows:
------------------- ----------------- ------------------ -----------------
Year Amount Year Amount
------------------- ----------------- ------------------ -----------------
(Millions of Dollars
2000 $302.5 2003 $298.3
2001 32.5 2004 178.8
2002 32.5
------------------- ----------------- ------------------ -----------------
Approximately $23.6 million of the portion of long-term debt payable in
2000 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 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 MGP until the 1960's, SCE&G
paid the City $26 million over a four-year period (1996-1999). Such amount was
deferred (see Note 1L)and 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
$143.1 million and $125.2 million at December 31, 1999 and 1998 at weighted
average interest rates of 6.63 percent and 5.32 percent, respectively.
Substantially all utility plant and fuel inventories are pledged as
collateral in connection with long-term debt.
The Company has a credit agreement with banks totaling $300 million for a
three-year term loan. The unused amount at December 31, 1999 was $300 million
(see Note 13).
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 a three-year
revolving credit agreement which expires December 19, 2000. The credit agreement
provides for a maximum amount of $125 million that may be outstanding at any
time. Since the credit agreement expires within one year, commercial paper
amounts outstanding have been classified as short-term debt instead of the
long-term classification of prior years.
Commercial paper outstanding totaled $70.2 million and $66.0 million at
December 31, 1999 and 1998 at weighted average interest rates of 6.44 percent
and 5.45 percent, respectively.
5. COMMON EQUITY:
The changes in "Common Stock," without par value, during 1999, 1998 and
1997 are summarized as follows:
- ---------------------------------------------------- ------------------------
Number of Shares Millions of Dollars
- ---------------------------------------------------- ------------------------
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
Changes in common stock - -
- ---------------------------------------------------- ------------------------
Balance December 31, 1999 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, 1999
approximately $29.7 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 during 1999, 1998 and 1997at
an annual rate per share of $1.32, $1.54 and $1.51, 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 2000 through 2004 is $2.8 million.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 1999, 1998 and 1997 are summarized as follows:
- ---------------------------------------------------- -----------------------
Number of Shares Millions of Dollars
- ---------------------------------------------------- -----------------------
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) (0.5)
- ---------------------------------------------------- -----------------------
Balance December 31, 1998 240,052 12.0
Shares Redeemed:
$50 par value (8,565) (0.4)
- ---------------------------------------------------- -----------------------
Balance December 31, 1999 231,487 $ 11.6
==================================================== =======================
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 percent 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 percent Junior Subordinated
Debentures due September 30, 2027. The sole asset of the Trust is $50.0 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 the Trust are redeemable only in
conjunction with the redemption of the related 7.55 percent 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 distributions.
7. INCOME TAXES:
Total income tax expense for 1999, 1998 and 1997 is as follows:
- ----------------------------------------------- ----------------- --------------
1999 1998 1997
- ----------------------------------------------- ----------------- --------------
- --------------------------------------------------------------------------------
(Millions of Dollars)
Current taxes:
Federal $ 94.5 $114.8 $101.3
State 0.6 2.2 (5.4)
- ----------------------------------------------- ----------------- --------------
- ----------------------------------------------- ----------------- --------------
Total current taxes 95.1 117.0 95.9
- ----------------------------------------------- ----------------- --------------
- ----------------------------------------------- ----------------- --------------
Deferred taxes, net:
Federal 6.1 2.3 3.5
State 1.5 2.0 0.3
- ----------------------------------------------- ----------------- --------------
- ----------------------------------------------- ----------------- --------------
Total deferred taxes 7.6 4.3 3.8
- ----------------------------------------------- ----------------- --------------
- ----------------------------------------------- ----------------- --------------
Investment tax credits:
Deferred - State 13.4 14.3 19.0
Amortization of amounts
deferred - State (1.2) (0.9) (1.5)
Amortization of amounts
deferred - Federal (3.6) (3.6) (3.6)
- ---------------------------------------------------------------- ---------------
- ---------------------------------------------------------------- ---------------
Total investment
tax credits 8.6 9.8 13.6
- ---------------------------------------------------------------- ---------------
================================================================ ===============
Total income tax
expense $111.3 $131.1 $113.6
================================================================ ===============
The difference in total income tax expense and the amount calculated from
the application of the statutory Federal income tax rate (35% for 1999, 1998 and
1997) to pre-tax income is reconciled as follows:
1999 1998 1997
(Millions of Dollars)
Net income $179.0 $223.4 $220.7
Total income tax expense:
Charged to operating expense 109.9 136.2 105.4
Charged (credited) to other items 1.4 (5.1) 8.2
Preferred stock dividends 7.4 7.5 9.2
===================================================== ==========================
Total pre-tax income $297.7 $362.0 $343.5
===================================================== ==========================
Income taxes on above at statutory
Federal income tax rate $104.2 $126.7 $120.2
Increases (decreases) attributed to:
State income taxes (less Federal
income tax effect) 9.3 11.4 8.1
Deferred income tax reversal at
higher than statutory rates (3.6) (3.7) (4.2)
Amortization of Federal investment
tax credits (3.6) (3.6) (3.6)
Allowance for equity funds used
during construction (2.8) (1.1) (2.5)
Non-deductible book basis for
assets sold 3.5 - -
Other differences, net 2.7 3.0 (4.4)
================================================= =============== ==============
Total income tax expense $111.3 $131.1 $113.6
================================================= =============== ==============
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $789.2 million at December 31, 1999 and
$606.2 million at December 31, 1998, (see Note 1I), are as follows:
1999 1998
- ----------------------------------------------------------- ------------------
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 62.8 $ 66.9
Cycle billing 15.5 20.6
Early retirement programs 14.8 13.0
Deferred compensation 8.8 7.4
Other postretirement benefits 36.6 32.9
Other 19.0 23.7
- ----------------------------------------------------------- ------------------
Total deferred tax assets 157.5 164.5
- ----------------------------------------------------------- ------------------
Deferred tax liabilities:
Property, plant and equipment 665.4 658.8
Pension expense 50.7 39.2
Research and experimentation 27.3 32.5
Reacquired debt 7.6 7.5
Investments in equity securities 184.7 20.5
Other 11.0 12.2
- ----------------------------------------------------------- ------------------
Total deferred tax liabilities 946.7 770.7
- ----------------------------------------------------------- ------------------
Net deferred tax liability $789.2 $606.2
=========================================================== ==================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of the Company through 1995, and is currently examining the
Company's Federal returns for 1996 and 1997. 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, 1999 and 1998 are as follows:
- --------------------------------------------------------------------------------
1999 1998
- --------------------------------------------------------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
(Millions of Dollars
Assets:
Cash and temporary cash investments $116.0 $116.0 $ 62.0 $ 62.0
Investments 941.8 1,952.4 409.7 464.7
Liabilities:
Short-term borrowings 266.5 266.5 194.4 194.4
Long-term debt 1,865.8 1,830.7 1,729.7 1,869.2
Preferred stock (subject to purchase
or sinking funds) 11.6 12.0 11.3
8.5
The information presented herein is based on pertinent information
available to the Company as of December 31, 1999 and 1998. 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, 1999, 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. 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, 1999, SCANA Communications Holdings, Inc. (SCH), a
wholly owned subsidiary of 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. SCH owns
approximately 4.9 million common shares of Powertel at a cost of
approximately $72.8 million. Powertel common stock closed at $100.375
per share on December 31, 1999, resulting in a pre-tax unrealized
holding gain of $417.8 million. The after-tax amount of such gain is
included in "Other Comprehensive Income." In addition, SCH 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 percent
series E ($75.0 million). Dividends on Preferred series E shares are
paid in common shares of Powertel. 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, as converted , the market value of
the underlying common shares for the preferred shares was
approximately $975.3 million at December 31, 1999, resulting in an
unrecorded pre-tax holding gain of $802.7 million.
o ITC^DeltaCom, Inc. (ITCD) is a fiber optic telecommunications
provider. SCH owns approximately 5.1 million common shares of ITCD at
a cost of approximately $42.7 million. ITCD common stock closed at
$27.625 per share on December 31, 1999, resulting in a pre-tax
unrealized holding gain of $98.3 million. The after-tax amount of such
gain is included in "Other Comprehensive Income." In addition, SCH
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. The market
value of series A preferred stock of ITCD is not readily determinable.
However, as converted, the market value of the underlying common stock
for the series A preferred stock was approximately $81.8 million at
December 31, 1999, resulting in an unrecorded pre-tax holding gain of
$70.6 million.
o Knology Holdings, Inc. (Knology) is a broad-band service provider of
cable television, telephone and internet services. SCH 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. In November 1999, SCH exercised 753
warrants to purchase 753 series A preferred shares of Knology at a
cost of $1.1 million. Immediately following this purchase, Knology
preferred shares split 600 for one, resulting in SCH's ownership of
451,800 shares. The market value of this investment is not readily
determinable.
o ITC has an ownership interest in several Southeastern communications
companies. SCH owns approximately 3.1 million common shares, 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 on a four to one basis. The
market value of these investments is not readily determinable.
On November 10, 1999 substantially all of the assets of SCANA Propane
Gas, Inc., SCANA Propane Storage, Inc., and C&T Pipeline, LLC (a wholly owned
subsidiary of Pipeline Corporation) were sold for approximately $94.5 million.
The resulting after-tax gain of $29.9 million was recorded in "Other Income."
Proceeds from the sale were used to reduce short-term debt.
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 (Note 3), at December 31, 1999 and
1998 and for the years then ended are as follows:
- ------------------------------------------------------------ ---------------
1999 1998
- ------------------------------------------------------------ ---------------
(Millions of Dollars)
Authorize lines of credit at year-end $558.3 $513.0
Unused lines of credit at year-end $505.0 $443.8
Short-term borrowings outstanding at year-end:
Bank loans $ 53.2 $ 69.2
Weighted average interest rate 7.80% 6.66%
Commercial paper 213.3 $125.2
Weighted average interest rate 6.63% 5.32%
- ------------------------------------------------------------ ---------------
10. COMMITMENTS AND CONTINGENCIES:
A. Lake Murray Dam Reinforcement
On October 15, 1999 the FERC notified SCE&G of its agreement with
SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case
of an extreme earthquake. SCE&G and FERC have been discussing possible
reinforcement alternatives for the dam over the past several years as part of
SCE&G's ongoing hydroelectric operating license with FERC. Costs of the
alternatives being discussed range up to approximately $195 million. Although
any costs incurred by SCE&G would be recoverable through electric rates, SCE&G
also is exploring alternative sources of funding. The project is to be completed
by the end of 2003.
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 $9.5 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 $3.3
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
MGPs, 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, which cost approximately $3.5 million, included excavation and
installation of several permanent barriers to mitigate coal tar seepage. 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 part of the
environmental settlement, SCE&G 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
2000.
SCE&G owns three other decommissioned MGP 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 be currently determined.
The Company and Westvaco each own a 50 percent 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. The
facility began operations in March 1999. Financing for the facility of
approximately $139.8 million was provided to Cogen by banks. On September 10,
1998 the contractor in charge of construction filed suit in South Carolina
Circuit Court seeking approximately $52 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.
On December 2, 1999 an unsuccessful bidder for the purchase of the
propane gas assets of SCANA filed suit against SCANA in Circuit Court seeking
unspecified damages. The suit alleges the existence of a contract for the sale
of assets to the plaintiff and various causes of action associated with that
contract. The Company is confident in its position and intends to vigorously
defend the lawsuit. 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.
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 and 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 and GENCO generation facilities.
Gas Distribution, comprised of SCE&G's local distribution operations, 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 of these segments are
regulated by the PSC. Energy Marketing markets electricity, natural gas and
other light hydrocarbons, primarily in the Southeast. Energy Marketing, doing
business as 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
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 regulated reportable segments share a similar regulatory
environment and, in some cases, overlapping service areas. 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 Adjustments/ Consolidated
1999 Operations Distribution Transmission Marketing Other Eliminations Total
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
External Customer Revenue $1,226 $234 $188 $431 $ 75 $ (504) $ 1,650
Intersegment Revenue 308 5 154 11 (478) - -
Operating Income (Loss 288 17 14 (5) 310
- (4)
Interest Expense 12 n/a 4 23 98 142
5
Depreciation & Amortization 148 13 7 13 (14) 168
1
Income Tax Expense/(Benefit) 1 n/a 7 (26) 21 107 110
Net Income 6 n/a 14 (49) 22 186 179
Segment Assets 4,751 399 253 144 1,269 (805) 6,011
Expenditures for Assets 201 19 8 30 (1) 261 4
Deferred Tax Assets 6 n/a 3 1 16 2 4
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
Electric Gas Gas Energy All Adjustments/ Consolidated
1998 Operations Distribution Transmission Marketing Other Eliminations Total
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
External Customer Revenue $1,220 $226 $ 185 $568 $ 69 $(636) $1,632
Intersegment Revenue 286 5 145 - 8 (444) -
Operating Income (Loss) 319 21 20 - (5) (10) 345
Interest Expense 11 n/a 4 - 19 89 123
Depreciation & Amortization 126 12 7 - 11 (11) 145
Income Tax Expense/(Benefit) 1 n/a 8 (8) (2) 137 136
Net Income 6 n/a 16 (14) (4) 219 223
Segment Assets 4,600 381 239 73 764 (776) 5,281
Expenditures for Assets 205 19 11 4 56 8 303
Deferred Tax Assets 5 n/a 3 - 9 5 22
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
Electric Gas Gas Energy All Adjustments/ Consolidated
1997 Operations Distribution Transmission Marketing Other Eliminations Total
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
External Customer Revenue $1,103 $ 231 $188 $207 $ 88 $ (294) $ 1,523
Intersegment Revenue 124 3 152 2 50 (331) -
Operating Income (Loss) 280 22 21 - (4) (5) 314
Interest Expense 12 n/a 4 - 14 91 121
Depreciation & Amortization 135 11 6 1 28 (28) 153
Income Tax Expense/(Benefit) 1 n/a 7 - 9 88 105
Net Income 5 n/a 18 (1) 19 180 221
Segment Assets 4,417 364 243 40 614 (746) 4,932
Expenditures for Assets 189 15 18 - 70 (4) 288
Deferred Tax Assets 6 n/a 5 - (1) 15 25
- ------------------------------- ----------- ------------- ------------- ----------- --------- -------------- ---------------
Revenues 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 the Company. These subsidiaries
conduct non-regulated operations in the electric, natural gas and
telecommunications industries. None of these subsidiaries met any of the
quantitative thresholds for determining reportable segments in 1999, 1998 or
1997. Significant non-cash activities included the Charleston electric franchise
agreement and the Charleston environmental agreement related to a MGP site.
Management uses operating income to measure segment profitability for
regulated operations. For non-regulated operations, management uses net income
for this purpose. Accordingly, SCE&G does not allocate interest charges or
income tax expense/(benefit) to the Electric Operations or Gas Distribution
segments. Similarly, management evaluates utility plant for segments
attributable to SCE&G and total assets for SCE&G as a whole, as well as for
other operating segments. Therefore, SCE&G does not allocate accumulated
depreciation, common and non-utility plant, or deferred tax assets to reportable
segments. However, GENCO does have interest charges, income taxes and deferred
tax assets which are included in Electric Operations. Interest income is not
reported by segment and is not material.
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 Net Income consist of SCE&G's unallocated net income.
Adjustments to assets consist of various reclassifications made for
external reporting purposes. 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.
Adjustments to Interest Charges, Income Tax Expense/(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.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1999
- ----------------------------------------------------------------------- -------
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- --------------------------------------------- -------------- ------------------
(Millions of Dollars, except per share amounts)
Total operating revenues $397 $375 $480 $398 $1,650
Operating income 78 65 109 58 310
Net income 37 24 67 51 179
Earnings per weighted average
share of common stock as reported .36 .23 .65 .49 1.73
- --------------------------------------------- ------------------ ---------------
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
- --------------------------------------------------------------------------------
13. COMPLETED ACQUISITION
On February 10, 2000, the Company completed its acquisition of Public
Service Company of North Carolina, Inc, (PSNC) and became a registered public
utility holding company under PUHCA. The transaction is being accounted for as a
purchase. The transaction is valued at approximately $900 million, including the
assumption of debt, and was financed through the issuance of two-year floating
rate notes and bank credit agreements totaling $700 million. .
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, (3) changes in the economy in
SCE&G's service territory, (4) the impact of competition from other energy
suppliers, (5) the management of SCE&G's operations, (6) growth opportunities,
(7) the results of financing efforts, (8) changes in SCE&G's accounting
policies, (9) weather conditions in areas served, (10) inflation, (11) changes
in environmental regulations and (12) 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, future prices of electricity, and
the regulatory actions which may be taken by the PSC, the FERC and the SEC 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 wholly owned
subsidiaries, SCANA Energy Marketing (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 the accelerated recovery of its electric
regulatory assets. SCE&G has 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 and billing system was implemented in 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 evolving operating environment.
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 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 SCE&G's results of operations in the period the
write-off would be 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 $188 million and $59 million
of regulatory assets and liabilities, respectively, including amounts recorded
for deferred income tax assets and liabilities of approximately $121million and
$43 million, respectively, on its balance sheet at December 31, 1999.
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 would be recorded. As of December 31, 1999, SCE&G's net investment in
fossil\hydroelectric generation and nuclear generation assets was $1,084.1
million and $602.3 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 percent 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. The
facility began operations in March 1999. Financing for the facility of
approximately $139.8 million was provided to Cogen by banks. On September 10,
1998 the contractor in charge of construction filed suit in Circuit Court
seeking approximately $52 million from Cogen, alleging that it incurred
construction cost overruns relating to the facility, 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 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 paid the City $26 million over a four-year period
(1996 through 1999). As part of the environmental settlement, SCE&G 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 2000, excluding
requirements for fuel liabilities and short-term borrowings and including notes
payable to affiliated companies, and the actual primary cash requirements for
1999 are as follows:
2000 1999
- --------------------------------------------------------- ---------------
(Millions of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $267 $222
Nuclear fuel expenditures 31 5
Maturing obligations, redemptions
and sinking and purchase fund requirements 105 19
- --------------------------------------------------------- ---------------
Total $403 $246
========================================================= ===============
Approximately 69% of total cash requirements (after payment of
dividends) was provided from internal sources in 1999 as compared to 78% in
1998.
SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1,
1945 (Old Mortgage), contains provisions prohibiting the issuance of additional
bonds thereunder (Class A Bonds) unless net earnings (as therein defined) for 12
consecutive months out of the 18 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, 1999 the Bond Ratio
was 6.01. The Old Mortgage allows the issuance of additional Class A Bonds to an
additional principal amount equal to (i) 70 percent of unfunded net property
additions (which unfunded net property additions totaled approximately $1,250
million at December 31, 1999), (ii) retirements of Class A Bonds (which
retirement credits totaled $91.8 million at December 31, 1999), 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 $715 million were available for such purpose as of December
31, 1999). New Bonds will be issuable under the New Mortgage only if adjusted
net earnings (as therein defined) for 12 consecutive months out of the 18 months
immediately preceding the month of issuance are at least twice the annual
interest requirements on all outstanding bonds (including Class A Bonds) and New
Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1999
the New Bond Ratio was 5.95.
On March 9, 1999 SCE&G issued $100 million of First Mortgage Bonds
having an annual interest rate of 6 1/8 percent and maturing on March 1, 2009.
The proceeds from the sale of these bonds were used to reduce short-term debt.
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 percent 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 12 months or less, but not later than December 31, 2001.
At December 31, 1999 SCE&G had $285 million of authorized lines of
credit which include a credit agreement for a maximum of $250 million to support
the issuance of commercial paper. Unused lines of credit at December 31, 1999
totaled $285 million. SCE&G's commercial paper outstanding at December 31, 1999
and December 31, 1998 was $143.1 million and $125.2 million, respectively. In
addition, Fuel Company has a credit agreement for a maximum of $125 million with
the full amount available at December 31, 1999. 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, 1999 was $70.2 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 12 consecutive
months immediately preceding the month of issuance are at least one and one-half
times the aggregate of all interest charges and preferred stock dividend
requirements (Preferred Stock Ratio). For the year ended December 31, 1999 the
Preferred Stock Ratio was 1.79.
SCE&G anticipates that its 2000 cash requirements of $526 million will
be met through internally generated funds (approximately 70%, 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 12 months and for
the foreseeable future.
On September 21, 1999 SCE&G announced a $180 million gas turbine
generator project in Aiken County, South Carolina. Two combined-cycle turbines
will burn natural gas to produce 300 megawatts of new electric generation and
use exhaust heat to replace coal-fired steam that powers two existing 75
megawatt turbines at the Urquhart Generating Station. The turbine project is
scheduled to be completed by June 2002.
On October 15, 1999 the FERC notified SCE&G of its agreement with
SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case
of an extreme earthquake. SCE&G and FERC have been discussing possible
reinforcement alternatives for the dam over the past several years as part of
SCE&G's ongoing hydroelectric operating license with FERC. Costs of the
alternatives being discussed range up to approximately $195 million. Although
any costs incurred by SCE&G would be recoverable through electric rates, SCE&G
also is exploring alternative sources of funding. The project is to be completed
by the end of 2003.
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 is meeting 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 have been
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
proposed in 2000.
SCE&G filed compliance plans with DHEC related to Phase II sulfur
dioxide requirements in 1995 and Phase II nitrogen oxide requirements in 1999,
1998 and 1997. SCE&G currently estimates that air emissions control equipment
will require capital expenditures of $48 million over the 2000-2004 period to
retrofit existing facilities, with increased operation and maintenance costs of
approximately $1 million per year. To meet compliance requirements through the
year 2009, SCE&G anticipates total capital expenditures of approximately $53
million.
The Federal Clean Water Act, as amended, provides for the imposition of
effluent limitations that require various levels of treatment for each
wastewater discharge. Under this Act, compliance with applicable limitations is
achieved under a national permit program. Discharge permits have been issued for
all and renewed for nearly all of SCE&G's 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. Amendments to the Clean Water Act proposed in
Congress include several provisions which, if passed, could prove costly to
SCE&G. These include, but are not limited to, limitations to mixing zones and
the implementation of technology-based standards.
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. These regulations 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 had recovered all amounts previously deferred for its electric
operations. SCE&G expects to recover all deferred amounts related to its gas
operations by December 2005. Deferral amounts, net of amounts recovered through
rates and insurance settlements, totaled $23.7 million and $21.3 million at
December 31, 1999 and 1998, 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 MGPs, 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, which cost approximately $3.5 million,
included excavation and installation of several permanent barriers to
mitigate coal tar seepage. 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. SCE&G estimates that the Record of Decision will
result in costs of approximately $13.3 million, of which approximately
$4 million remains. 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. However, SCE&G submitted a
Comprehensive Remedial Design Work Plan on December 17, 1999, and is
proceeding with implementation pending agency approval.
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 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 MGP 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 September 14, 1999 the PSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan will be implemented beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery methodology wherein SCE&G will increase depreciation of its Cope
Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of revenues and
operating expenses, not to exceed $36 million annually without the approval of
the PSC. Any unused portion of the $36 million in any given year could be
carried forward for possible use in the subsequent year. The accelerated capital
recovery plan will be accomplished through existing customer rates.
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 12 months ended September 30, 1998. This return on
common equity exceeded SCE&G's authorized return of 12 percent by 1.04 percent,
or $22.7 million, primarily as a result of record-breaking heat experienced
during the summer. The order required prospective rate reductions on a per
kilowatt-hour basis, based on actual retail sales for the 12 months ended
September 30, 1998. . 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 percent. The rate reductions were placed into
effect with the first billing cycle of January 1999.
On January 9, 1996 the PSC issued an order granting SCE&G an increase in
retail electric rates which were fully implemented by January 1997. The PSC
authorized a return on common equity of 12.0 percent. 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 $9.8 million 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.
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.
Other Matters
SCE&G successfully completed its efforts to ensure Year 2000 readiness
for all of its critical systems. As a result, SCE&G experienced no interruption
in the services it provides to its customers during the transition to the Year
2000. Although SCE&G has not experienced any Year 2000 problems, there can be no
guarantees that there will not be any Year 2000 problems in the future. The cost
of SCE&G's Year 2000 efforts totaled approximately $15.8 million.
RESULTS OF OPERATIONS
Net Income
Net income and the percent increase from the previous year for the years
1999, 1998 and 1997 were as follows:
1999 1998 1997
- ---------------------------------------------- ----------- ----------
(Millions of Dollars)
Net income $189.2 $227.2 $194.7
Percent increase (decrease)
in net income (16.75%) 16.72% 2.19%
- ---------------------------------------------- ----------- ----------
o 1999 Net income decreased for the year primarily due to a rate
reduction, milder weather, and higher fuel costs. In addition,
completion of a new customer billing system and cogeneration
facility, among other factors, resulted in increased operating and
depreciation expenses. These factors were partially offset by
customer growth and pension income. Also affecting the decrease in
net income was the depreciation reduction recorded in 1998 (as
discussed below).
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.
Pension income recorded by SCE&G reduced operations expense by $16.3
million, $16.6 million and $11.7 million for the years ended December 31, 1999,
1998 and 1997, respectively. In addition, pension income increased other income
by $10.5 million and $9.0 million for the years ended December 31, 1999 and
1998, respectively. The reductions to operations expense for 1998 and 1997 were
substantially offset by accelerated amortizations of a significant portion of
the transition obligation for postretirement benefits other than pensions and
certain regulatory assets as approved by the PSC.
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 2.0 percent of income before income
taxes in 1999, 3.8 percent in 1998 and 4.0 percent in 1997.
Electric Operations
Electric operations sales margins for 1999, 1998 and 1997 were as follows:
1999 1998 1997
- -------------------------------------------------- ----------- ------------
- ----------------------------------------------------------------------------
(Millions of Dollars)
Electric revenue $1,226.0 $1,219.8 $1,103.1
Less: Fuel used in electric generation
214.4 212.3 181.0
Purchased power
141.4 116.4 109.2
- -----------------------------------------------------------------------------
Margin $ 870.2 $891.1 $812.9
=============================================================================
o 1999 The sales margin decreased for 1999 primarily due to a rate
reduction, milder weather and higher fuel costs. These factors
were partially offset by customer growth.
o 1998 The sales margin increased for 1998 primarily due to more
favorable weather and customer growth.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes were as follows:
Classification 1999 % Change 1998 % Change
---------------------------------------------------------------- -------------
Residential (55,208) (0.9%) 676,578 12.0%
Commercial 52,440 0.9% 577,852 10.9%
Industrial 316,087 5.4% 389,931 7.2%
Sales for Resale (excluding
interchange) 63,304 5.6% 65,367 6.2%
Other (17,652) (3.3%) 29,823 5.9%
---------------------------------------------------------------- -------------
Total territorial 358,971 - 1,739,551 -
Negotiated Market Sales Tariff 183,442 12.3% 610,784 69.1%
------------------------------------------------------------------ -----------
Total 542,413 2.6% 2,350,335 12.5%
================================================================== ===========
o 1999 The sales volume decrease for residential was primarily due
to milder weather which was partially offset by customer growth.
Volumes for the remaining classes increased primarily due to
customer growth.
o 1998The sales volume increases for 1998 were primarily due to more
favorable weather and customer growth.
Gas Distribution
Gas sales margins for 1999, 1998 and 1997 were as follows:
1999 1998 1997
------------------------------------------------ -------------- ------------
(Millions of Dollars)
Gas operating revenues $239.0 $230.4 $233.6
Less: Gas purchased for resale 152.6 142.4 151.9
------------------------------------------------ -------------- ------------
Margin $ 86.4 $ 88.0 $ 81.7
================================================ ============== ============
o 1999 The sales margin decreased for 1999 primarily as a result of higher
gas costs.
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.
Increases (decreases) from the prior year in dekatherm (DT) sales volume by
classes, including transportation gas, were as follows:
Classification 1999 % Change 1998 % Change
------------------------------ ------------- ------------ ------------
Residential (94,027) (0.8%) (2,685) 0.0%
Commercial 404,654 3.6% 389,468 3.6%
Industrial 644,485 3.7% 1,965,506 12.8%
Transportation gas (28,732) (1.4%) (673,795) (25.2%)
Total 926,380 2.2% 1,678,494 4.1%
============================== ============= ============ ============
o 1999The gas sales volume increases for 1999 were primarily due to
customer expansion and customer growth. Residential volume decreased
primarily due to milder weather.
o 1998 The sales volume for commercial and industrial customers
increased for 1998 as a result of lower gas prices and increased sales
to electric generation facilities.
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including taxes, were as
follows:
1999 1998
- ------------------------------------------------ ---------------------
(Millions of Dollars)
Other operation and maintenance $ 6.5 $27.4
Depreciation and amortization 23.2 (9.0)
Income taxes (24.8) 29.9
Other taxes 1.8 5.6
- ------------------------------------------------ ---------------------
Total $ 6.7 $53.9
================================================ =====================
o 1999Other operation and maintenance increased primarily due to
a shift in labor from capital to expense related to the
completion of a new customer billing system, a cogeneration
facility becoming operational, and other operating costs.
Thesecosts were partially offset by pension income, which in 1998
had been offset by the accelerated amortization of the Company's
transition obligation expense for post-retirement benefits and
other regulatory assets. Depreciation and amortization increased
primarily due to the impact of the non-recurring adjustment to
depreciation expense discussed under Net Income, increased
amortization due to completion of a new customer billing system,
and normal increases in utility plant. Income taxes decreased
primarily due to decreased operating income. Other taxes
increased primarily due to increased property taxes.
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.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
1999 1998
- ------------------------------------------------- ---------------------
(Millions of Dollars)
Interest on long-term debt, net $1.9 $(1.4)
Other interest expense 2.4 1.3
- ------------------------------------------------- ---------------------
Total $4.3 $(0.1)
================================================= =====================
Interest expense increased over 1998 as a result of increased borrowings
and increased weighted average interest rates on short-term and long-term
borrowings. Interest expense did not change materially in 1998.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations, the table presents principal cash flows and related weighted
average interest rates by expected maturity dates.
December 31, 1999 Expected Maturity Date
-------------------------------------------------------
(Millions of Dollars)
Liabilities 2000 2001 2002 2003 2004 Thereafter Total Fair Value
---------- -------- --------- ----------- --------- ---
Long-Term Debt:
Fixed Rate ($) 127.5 27.6 27.6 129.4 123.9 933.0 1,369.0 1,232.7
Average Interest Rate 6.16 6.73 6.73 6.37 7.52 7.72 7.39
December 31, 1998 Expected Maturity Date
-------------------------------------------------------
(Millions of Dollars)
Liabilities 2000 2001 2002 2003 2004 Thereafter Total Fair Value
---------- -------- --------- ----------- --------- ---
Long-Term Debt:
Fixed Rate ($) 29.0 188.5 22.6 22.6 124.5 943.4 1,333.6 1,356.4
Average Interest Rate 6.56 5.89 6.72 6.72 6.95 7.73 7.11
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
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report.............................................. 80
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1999 and 1998.......... 81
Consolidated Statements of Income and Retained Earnings for years
ended December 31, 1999, 1998 and 1997............................. 83
Consolidated Statements of Cash Flows for the years ended December
31, 1999, 1998 and 1997........................................... 84
Consolidated Statements of Capitalization as of December
31, 1999 and 1998................................................ 85
Notes to Consolidated Financial Statements............................ 87
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, 1999 and 1998 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, 1999. Our audits also included the financial statement
schedule listed in Part IV at Item 14. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule 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,
1999 and 1998 and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1999 in conformity with
generally accepted accounting principles. Also, in our opinion, such financil
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 10 , 2000
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1999 1998
- --------------------------------------------------------------------------------------------
(Millions of Dollars)
ASSETS
Utility Plant (Notes 1, 3 & 4):
Electric $4,337 $4,133
Gas 392 366
Other 191 175
- -------------------------------------------------------------------------------------------
Total 4,920 4,674
Less accumulated depreciation and amortization 1,611 1,517
- -------------------------------------------------------------------------------------------
Total 3,309 3,157
Construction work in progress 149 219
Nuclear fuel, net of accumulated amortization 43 56
- -------------------------------------------------------------------------------------------
Utility Plant, Net 3,501 3,432
- -------------------------------------------------------------------------------------------
Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 19 16
- -------------------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments (Note 8) 78 36
Receivables - customer and other 195 178
Inventories (At average cost):
Fuel (Notes 1, 3 & 4) 30 32
Materials and supplies 48 47
Prepayments 8 8
Deferred income taxes (Note 7) 16 21
- -------------------------------------------------------------------------------------------
Total Current Assets 375 322
- -------------------------------------------------------------------------------------------
Deferred Debits:
Emission allowances 31 31
Environmental 24 22
Nuclear plant decommissioning fund (Note 1) 64 56
Pension asset, net (Note 1) 144 115
Other regulatory assets 164 180
Other (Note 1) 82 72
- -------------------------------------------------------------------------------------------
Total Deferred Debits 509 476
- -------------------------------------------------------------------------------------------
Total $4,404 $4,246
===========================================================================================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1999 1998
- --------------------------------------------------------------------------------------------
(Millions of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment:
Common equity (Note 5) $1,558 $1,499
Preferred stock (Not subject to purchase or sinking funds) 106 106
- -------------------------------------------------------------------------------------------
Total Stockholders' Investment 1,664 1,605
Preferred Stock, net (Subject to purchase or sinking
funds)(Notes 6 & 8) 11 11
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 (Note 6) 50 50
Long-Term Debt, net (Notes 3 & 8) 1,121 1,206
- -----------------------------------------------------------------------------------------
Total Capitalization 2,846 2,872
- -------------------------------------------------------------------------------------------
Current Liabilities:
Short-term borrowings (Notes 4, 8 & 9) 213 125
Current portion of long-term debt (Note 3) 128 29
Accounts payable 78 97
Accounts payable - affiliated companies (Notes 1 & 3) 33 23
Customer deposits 17 17
Taxes accrued 60 75
Interest accrued 22 21
Dividends declared 28 38
Other 10 10
- -------------------------------------------------------------------------------------------
Total Current Liabilities 589 435
- -------------------------------------------------------------------------------------------
Deferred Credits:
Deferred income taxes (Notes 1 & 7) 560 549
Deferred investment tax credits (Notes 1 & 7) 108 100
Reserve for nuclear plant decommissioning (Note 1) 64 56
Postretirement benefits (Note 1) 98 87
Regulatory liabilities 59 65
Other (Note 1) 80 82
- -------------------------------------------------------------------------------------------
Total Deferred Credits 969 939
- -------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 10) - -
Total $4,404 $4,246
===========================================================================================
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------
(Millions of Dollars)
Operating Revenues (Notes 1 & 2):
Electric $1,226 $1,220 $1,103
Gas 239 230 234
Transit 2 1 1
- --------------------------------------------------------------------------------------------
Total Operating Revenues 1,467 1,451 1,338
- --------------------------------------------------------------------------------------------
Operating Expenses:
Fuel used in electric generation 214 212 181
Purchased power (including affiliated
purchases)(Note 1) 142 116 109
Gas purchased from affiliate for resale (Note 1) 153 142 152
Other operation 239 239 222
Maintenance (Note 1) 85 79 67
Depreciation and amortization (Note 1) 154 131 140
Income taxes (Notes 1 & 7) 103 128 98
Other taxes 94 92 87
- --------------------------------------------------------------------------------------------
Total Operating Expenses 1,184 1,139 1,056
- --------------------------------------------------------------------------------------------
Operating Income 283 312 282
- --------------------------------------------------------------------------------------------
Other Income (Note 1):
Allowance for equity funds used during construction 3 7 6
Other income (loss), net of income taxes 9 6 3
- --------------------------------------------------------------------------------------------
Total Other Income 12 13 9
- --------------------------------------------------------------------------------------------
Income Before Interest Charges 295 325 291
- ---------------------------------------------------------------------------------------------
Interest Charges (Credits):
Interest on long-term debt, net 97 95 96
Other interest expense (Notes 1 & 3) 8 6 5
Allowance for borrowed funds used
during construction (Note 1) (3) (7) (6)
- --------------------------------------------------------------------------------------------
Total Interest Charges, Net 102 94 95
- --------------------------------------------------------------------------------------------
Income Before Preferred Dividend Requirements on
Mandatorily Redeemable Preferred Securities 193 231 196
Preferred Dividend Requirement of
Company - Obligated Mandatorily Redeemable
Preferred Securities 4 4 1
- --------------------------------------------------------------------------------------------
Net Income 189 227 195
Preferred Stock Cash Dividends (At stated rates) (7) (8) (9)
- --------------------------------------------------------------------------------------------
Earnings Available for Common Stock 182 219 186
Retained Earnings at Beginning of Year 491 438 415
Common Stock Cash Dividends Declared (Note 5) (123) (166) (163)
- --------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 550 $ 491 $ 438
============================================================================================
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------------------
(Millions of Dollars)
Cash Flows From Operating Activities:
Net income $189 $ 227 $ 195
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 154 131 140
Amortization of nuclear fuel 18 20 19
Deferred income taxes, net 16 49 16
Pension asset (29) (33) (24)
Postretirement benefits 11 26 24
Other regulatory assets 16 (23) 39
Other regulatory liabilities (6) 4 6
Allowance for funds used during construction (6) (14) (12)
Over (under) collection, fuel adjustment clause (6) 1 -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (17) (13) 6
(Increase) decrease in inventories 1 (8) 8
Increase (decrease) in accounts payable (9) 35 (13)
Increase (decrease) in taxes accrued (15) 30 (22)
Other, net (7) 9 (14)
- -----------------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 310 441 368
- ------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, net of AFC (227) (252) (232)
Increase in nonutility property and investments (3) (1) (5)
- ------------------------------------------------------------------------------------------
Net Cash Used For Investing Activities (230) (253) (237)
- ------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds and other long-term debt 99 - 1
Issuance of company - obligated mandatorily
redeemable trust preferred securities - - 49
Equity contributions from parent - - 12
Issuance of preferred stock - - 99
Repayments:
Mortgage bonds - (50) (15)
Other long-term debt (9) (11) -
Preferred stock - (1) (53)
Repayment of bank notes (10) - -
Repayment of bank loans - - (10)
Dividend Payments:
Common stock (133) (187) (141)
Preferred stock (7) (7) (9)
Short-term borrowings, net 88 112 (77)
Fuel and emission allowance financings, net (66) (14) 14
- ------------------------------------------------------------------------------------------
Net Cash Used For Financing Activities (38) (158) (130)
- ------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Temporary Cash Investments 42 30 1
Cash and Temporary Cash Investments, January 1 36 6 5
- ------------------------------------------------------------------------------------------
Cash and Temporary Cash Investments, December 31 $ 78 $ 36 $ 6
==========================================================================================
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $3, $7 and $6) $102 $ 101 $ 98
- Income taxes 109 92 (48)
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1999 1998
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 437 437
Capital stock expense (5) (5)
Retained earnings 550 491
- -----------------------------------------------------------------------------------------------------------------
Total Common Equity 1,558 55% 1,499 52%
- ----------------------------------------------------------------------------------------------------------------
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 1999 1998
$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 & 8):
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 1999 and 1998
$50 Par Value - Authorized 1,571,487 shares
Shares Outstanding Redemption Price
Series 1999 1998
4.50% 11,200 12,800 51.00 1 1
4.60%(A) 18,052 20,052 51.00 1 1
4.60%(B) 61,200 64,600 50.50 3 3
5.125% 68,000 69,000 51.00 3 3
6.00% 73,035 73,600 50.50 4 4
-------------------
Total 231,487 240,052
===================
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1999 and 1998
Total Preferred Stock (Subject to purchase or sinking funds) 12 12
Less: Current portion, including sinking fund requirements 1 1
- ----------------------------------------------------------------------------------------------------------------
Total Preferred Stock, Net (Subject to purchase or sinking funds) 11 11
- ----------------------------------------------------------------------------------------------------------------
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, 1999 1998
- ------------------------------------------------------------------------------------------------------
(Millions of Dollars)
Long-Term Debt (Notes 3, 4 & 8):
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100 100
6 1/4% 2003 100 100
7.70% 2004 100 100
6 1/8% 2009 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
9% 2006 131 131
8 7/8% 2021 103 114
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 17 16
Commercial Paper - 66
Charleston Franchise Agreement due 1997-2002 11 14
Charleston Environmental Agreement - 6
Other 3 4
- ------------------------------------------------------------------------------------------------------
Total Long-Term Debt 1,252 1,238
Less: Current maturities, including sinking fund requirements 128 29
Unamortized discount 3 3
- ------------------------------------------------------------------------------------------------------
Total Long-Term Debt, Net 1,121 39% 1,206 42%
- -----------------------------------------------------------------------------------------------------
Total Capitalization $2,846 100% $2,872 100%
=====================================================================================================
See Notes to Consolidated Financial Statements.
156
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, 1999 and 1998, the Company had approximately
$20.9 million and $16.1 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, 1999 and 1998 the Company had approximately $9.2 million and
$5.8 million, respectively, payable to GENCO for unit power purchases. Such unit
power purchases, which are included in "Purchased power," amounted to
approximately $105.5 million, $85.0 million and $99.8 million in 1999, 1998 and
1997, respectively.
Total interest income, based on market interest rates, associated with
the Company's advances to affiliated companies was approximately $921,000,
$281,000 and $20,000 in 1999, 1998 and 1997, respectively.
In 1999, 1998 and 1997 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, 1999,
approximately $188 million and $59 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets and
liabilities of approximately $121 million and $43 million, respectively. The
electric and gas regulatory assets of approximately $35 million and $34 million,
respectively (excluding deferred income tax assets) are being recovered through
rates and, as discussed in Note 2C, the Public Service Commission of South
Carolina (PSC) has approved accelerated recovery of approximately $7 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 the
write-off would be 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 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 $959.7 million and $983.3 million as of December 31, 1999 and
1998, respectively. Accumulated depreciation associated with the Company's share
of Summer Station was approximately $365.1 million and $369.2 million as of
December 31, 1999 and 1998, 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 7.7%, 8.5% and
8.8% for 1999, 1998 and 1997, 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 $10.1 million and $3.1 million at
December 31, 1999 and 1998, 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, 1999 and 1998 the Company had
undercollected through the gas cost recovery procedure approximately $4.1
million and $5.2 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 2.99%, 3.02% and 3.09% for 1999, 1998 and 1997, 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 are estimated, in 2022 dollars assuming a 4.5 percent
annual rate of inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated decommissioning costs
of Summer Station over the life of Summer Station. The Company's method of
funding decommissioning costs is referred to as COMReP (Cost of Money Reduction
Plan). Under this plan, funds collected through rates ($3.2 million in each of
1999 and 1998) 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 $3.2 million at December 31, 1999, 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
all significant 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 and Other Postretirement Benefits
The Company participates in SCANA's 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. 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 $0.7 million, $15.7 million and $15.6 million for the years ended
December 31, 1999, 1998 and 1997, respectively. (See Note 2C.)
Disclosures 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
1999 1998 1997 1999 1998 1997
(Millions of Dollars) (Millions of Dollars)
Service Cost 10.0 8.3 6.8 3.0 2.6 2.5
Interest Cost 27.9 25.9 23.5 9.5 9.4 7.8
Expected return on assets (65.5) (59.3) (41.6) N/A N/A N/A
Prior service cost amortization 1.1 1.1 1.1 0.7 0.7 0.7
Actuarial (gain) loss (8.6) (9.6) (7.0) 1.2 1.0 0.1
Transition amount amortization 0.8 0.8 0.8 1.7 19.1 18.9
Special termination benefit cost 5.5 0.0 0.0 1.0 0.0 0.0
Amounts contributed (by) to
Company affiliates 1.1 0.3 0.3 (0.9) (0.7) (0.7)
Net periodic benefit (income)
cost (27.7) (32.5) (16.1) 16.2 32.1 29.3
Weighted-Average Assumptions as of December 31
Other
Retirement Benefits Postretirement Benefits
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
Discount rate 8.0% 7.0% 7.5% 8.0% 7.0% 7.5%
Expected return on plan assets 9.5% 9.5% 8.0% N/A N/A N/A
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Change in Benefit Obligation
Other
Retirement Benefits Postretirement Benefits
1999 1998 1999 1998
(Millions of Dollars) (Millions of Dollars)
Benefit obligation, Jan. 1 389.3 344.4 137.0 108.8
Service cost 10.0 8.3 3.0 2.6
Interest cost 27.9 25.9 9.5 9.4
Plan participants' contributions 0.1 0.1 0.5 0.5
Actuarial loss (gain) (51.6) 28.3 (14.5) 23.3
Benefits paid (18.9) (17.7) (6.7) (7.6)
Special termination benefit cost 5.5 0.0 1.0 0.0
Benefit obligation, Dec. 31 362.3 389.3 129.8 137.0
Change in Plan Assets
Retirement Benefits
1999 1998
(Millions of Dollars)
Fair value of plan assets, Jan. 1 698.8 632.9
Actual return on plan assets 103.0 83.5
Company contribution - -
Plan participants' contributions 0.1 0.1
Benefits paid (18.9) (17.7)
Fair value of plan assets, Dec. 31 783.0 698.8
The Company does not fund postretirement benefits other than pensions.
Funded Status of Plans
Other
Retirement Benefits Postretirement Benefits
1999 1998 1999 1998
(Millions of Dollars) (Millions of Dollars)
Funded status, Dec. 31 420.8 309.5 (129.8) (137.0)
Unrecognized actuarial (gain)/loss (294.0) (213.4) 18.8 34.5
Unrecognized prior service cost 11.3 12.3 4.3 5.1
Unrecognized net transition
obligation 5.6 6.5 9.1 10.7
----- ----- ----- -----
Net amount recognized 143.7 114.9 (97.6) (86.7)
Health Care Trends
The determination of net periodic postretirement benefit cost is based on the
following assumptions:
1999 1998 1997
- ----------------------------------------------------- ------------ -------------
Health care cost trend rate 8.0% 8.5% 9.0%
Ultimate health care cost trend rate 5.5% 5.0% 5.5%
Year achieved 2005 2005 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 (0.2)
Effect on postretirement obligation 2.9 (3.3)
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium, discount and expense are being amortized as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues. Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.
L. Environmental
The Company has an environmental assessment program to identify and assess
current and former operations sites that could require environmental cleanup. As
site assessments are initiated, 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, 1999 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 2005.
Deferred amounts, net of amounts recovered through rates and insurance
settlements, totaled $23.7 million and $21.3 million at December 31, 1999 and
1998, respectively. The deferral includes the estimated costs 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.
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, 2001, 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 1999 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 September 14, 1999 the PSC approved an accelerated capital recovery
plan for the Company's Cope Generating Station. The Plan was implemented
beginning January 1, 2000 for a three-year period. The PSC approved an
accelerated capital recovery methodology wherein the Company will increase
depreciation of its Cope Generating Station in excess of amounts that would be
recorded based upon currently approved depreciation rates. The amount of the
accelerated depreciation will be determined by the Company based on the level of
revenues and operating expenses, not to exceed $36 million annually without the
approval of the PSC. Any unused portion of the $36 million in any given year
could be carried forward for possible use in the subsequent year. The
accelerated capital recovery plan will be accomplished through existing customer
rates.
B. 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 12 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-breaking heat experienced during the summer. The order required
prospective rate reductions on a per kilowatt-hour basis, based on actual retail
sales for the 12 months ended September 30, 1998. On January 12, 1999 the PSC
denied the Company's motion for reconsideration. However, the PSC also ruled
that no further rate action was required, and reaffirmed the Company's return on
equity of 12 percent. The rate reductions were placed into effect with the first
billing cycle of January 1999.
C. On January 9, 1996 the PSC issued an order granting the Company an
increase in retail electric rates which were fully implemented by January 1997.
The PSC authorized a return on common equity of 12.0 percent. 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 $9.8 million
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.
D. 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 (MGPs). 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 1999, as a result of the annual review, the
PSC approved the Company's request to maintain the billing surcharge at $.011
per therm to provide for the recovery of the remaining balance of $24.2 million.
E. 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 and sinking fund
requirements for the years 2000 through 2004 are summarized as follows:
------------------- ----------------- ------------------ -----------------
Year Amount Year Amount
------------------- ----------------- ------------------ -----------------
(Millions of Dollars
2000 $127.5 2003 $129.4
2001 27.6 2004 123.9
2002 27.6
------------------- ----------------- ------------------ -----------------
Approximately $23.6 million of the portion of long-term debt payable in
2000 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 MGP until the 1960's, the Company paid the City $26 million over a
four-year period (1996-1999). Such amount was deferred (see Note 1L) and
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 $143.1million and $125.2 million at December 31, 1999 and
1998, at weighted average interest rates of 6.63 percent and 5.32 percent,
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 a three-year
revolving credit agreement which expires December 19, 2000. The credit agreement
provides for a maximum amount of $125 million that may be outstanding at any
time. Since the credit agreement expires within one year, commercial paper
amounts outstanding have been classified as short-term debt instead of the
long-term classification of prior years.
Commercial paper outstanding totaled $70.2 million and $66.0 million at
December 31, 1999 and 1998 at weighted average interest rates of 6.44 percent
and 5.45 percent, respectively.
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including Preferred Stock Not
Subject to Purchase or Sinking Funds) during 1999, 1998 and 1997 are summarized
as follows:
Common Shares Preferred Shares Millions of Dollars
- -------------------------------------------------------------------------------------- --------------------
Balance December 31, 1996 10,296,147 322,877 $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 including
transfer of assets 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: 227.2
Net income
Cash Dividends Declared:
Preferred Stock (at stated rates) (7.5)
Common Stock (167.3)
Other Paid in Capital (0.2)
- -------------------------------------------------------------------------------------- --------------------
Balance December 31, 1998 40,296,147 1,125,209 1,605.2
Changes in Retained Earnings
Net Income 189.1
Cash Dividends Declared:
Preferred Stock (at stated rates) (7.4)
Common Stock (122.4)
- -------------------------------------------------------------------------------------- --------------------
Balance December 31, 1999 40,296,147 1,125,209 $1,664.5
====================================================================================== ====================
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 certain earnings therefrom. At
December 31, 1999 approximately $29.7 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 2000 through 2004 is $2.8 million.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 1999, 1998 and 1997 are summarized as follows:
- ----------------------------------------------------- -----------------------
Number of Shares Millions of Dollars
- ----------------------------------------------------- -----------------------
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) (0.5)
- ----------------------------------------------------- -----------------------
Balance December 31, 1998 240,052 12.0
Shares Redeemed:
$50 par value (8,565) (0.4)
- ----------------------------------------------------- -----------------------
Balance December 31, 1999 231,487 $ 11.6
===================================================== =======================
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 percent
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 percent 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 the Indenture pursuant to which the Junior
Subordinated Debentures were 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 percent 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, 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 distributions.
7. INCOME TAXES:
Total income tax expense for 1999, 1998 and 1997 is as follows:
- ----------------------------------------------- -----------------------------
1999 1998 1997
- ----------------------------------------------------------------------------
(Millions of Dollars)
Current taxes:
Federal $ 91.3 $116.1 $ 88.0
State 0.3 2.1 (6.9)
- -------------------------------------------- ------------- ------------
Total current taxes 91.6 118.2 81.1
- -------------------------------------------- ------------- -------------
Deferred taxes, net:
Federal 7.7 1.8 3.7
State 1.4 2.0 1.5
- -------------------------------------------- ------------- -------------
Total deferred taxes 9.1 3.8 5.2
- --------------------------------------------------------------
Investment tax credits:
Deferred - State 13.4 14.3 19.0
Amortization of amounts
deferred - State (1.2) (0.9) (1.5)
Amortization of amounts
deferred - Federal (3.2) (3.2) (3.2)
- -------------------------- ----------------- ------------
Total investment tax credits 9.0 10.2 14.3
- -------------------------------------------------- ------------- --------------
================================================== ============= ==============
Total income tax expense $109.7 $132.2 $100.6
================================================== ============= ==============
The difference in total income tax expense and the amount calculated from
the application of the statutory Federal income tax rate (35% for 1999, 1998 and
1997) to pre-tax income is reconciled as follows:
- ------------------------------------------------------------------------ -------
1999 1998 1997
- ------------------------------------------------------------- -------------- ---
(Millions of Dollars)
Net income $189.2 $227.2 $194.7
Total income tax expense:
Charged to operating expense 103.1 127.9 98.1
Charged (credited) to other items 6.6 4.2 2.5
============================================================= ========= ========
Total pre-tax income $298.9 $359.3 $295.3
============================================================= ========= ========
Income taxes on above at statutory Federal
income tax rate $104.6 $125.8 $103.4
Increases (decreases) attributed to:
State income taxes (less Federal income tax effect) 9.0 11.4 7.9
Deferred income tax reversal at
higher than statutory rates (3.0) (3.1) (3.5)
Amortization of Federal investment tax credits (3.2) (3.2) (3.2)
Allowance for equity funds used during construction (2.4) (0.9) (2.1)
Other differences, net 3.3 3.6 (1.9)
============================================================= ==================
Total income tax expense $109.7 $132.2 $100.6
============================================================= ==================
The tax effects of significant temporary differences comprising the Company's
net deferred tax liability of $544.8 million at December 31, 1999 and $528.2
million at December 31, 1998 (see Note 1I), are as follows:
- ------------------------------------------------------ ------------------
1999 1998
- ------------------------------------------------------ ------------------
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 57.9 $ 61.7
Cycle billing 15.5 20.6
Early retirement programs 14.8 13.0
Deferred compensation 8.6 7.2
Other postretirement benefits 36.6 32.9
Other 11.1 12.0
- ------------------------------------------------------ ------------------
Total deferred tax assets 144.5 147.4
- ------------------------------------------------------ ------------------
Deferred tax liabilities:
Property, plant and equipment 593.5 584.9
Pension expense 50.7 39.2
Reacquired debt 7.6 7.5
Research and experimentation 27.3 32.5
Deferred fuel 5.5 3.4
Other 4.7 8.1
- ------------------------------------------------------ ------------------
Total deferred tax liabilities 689.3 675.6
- ------------------------------------------------------ ------------------
Net deferred tax liability $544.8 $528.2
====================================================== ==================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of SCANA through 1995, and is currently examining SCANA's
Federal returns for 1996 and 1997. 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, 1999 and 1998 are as follows:
- ------------------------------------------------------------------- ------------
1999 1998
- ---------------------------------------------------------------- ---------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
- ---------------------------------------------------------------- ---------------
(Millions of Dollars
Assets:
Cash and temporary cash investments $ 78.4 $ 78.4 $ 35.6 $ 35.6
Investments 5.1 4.7 4.7 5.1
Liabilities:
Short-term borrowings 213.3 213.3 125.2 125.2
Long-term debt 1,248.6 1,232.7 1,234.8 1,356.4
Preferred stock (subject to
purchase or sinking funds) 11.6 11.5 11.3 8.5
The information presented herein is based on pertinent information
available to the Company as of December 31, 1999 and 1998. 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, 1999, 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. 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 (Note 3 ), at December 31, 1999 and
1998 and for the years then ended are as follows:
- -------------------------------------------------------------- ---------------
1999 1998
- -------------------------------------------------------------- ---------------
(Millions of Dollars)
Authorize lines of credit at year-end $410 $513.0
Unused lines of credit at year-end $410 $443.8
Short-term borrowings outstanding at year-end:
Commercial paper 213.3 $125.2
Weighted average interest rate 6.63% 5.32%
- -------------------------------------------------------------- ---------------
10. COMMITMENTS AND CONTINGENCIES:
A. Lake Murray Dam Reinforcement
On October 15, 1999 the FERC notified the Company of its agreement with
the Company's plan to reinforce Lake Murray Dam in order to maintain the lake in
case of an extreme earthquake. The Company and FERC have been discussing
possible reinforcement alternatives for the dam over the past several years as
part of the Company's ongoing hydroelectric operating license with FERC. Costs
of the alternatives being discussed range up to approximately $195 million.
Although any costs incurred by the Company would be recoverable through electric
rates, the Company also is exploring alternative sources of funding. The project
is to be completed by the end of 2003.
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 $9.5 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 facility covered under the NEIL program. Based on the current
annual premium, this retroactive premium assessment would not exceed $3.3
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 Environmental Protection Agency (EPA) notified the
Company, the City of Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the Calhoun Park area
site in Charleston, South Carolina. This site 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 MGPs, 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 Potential
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 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, which
cost approximately $3.5 million, included excavation and installation of several
permanent barriers to mitigate coal tar seepage. 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 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 the Company involving the
Calhoun Park area for a payment of $26 million over four years (1996-1999) by
the Company 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 part
of the environmental settlement, the Company 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 MGP 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 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 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 be currently determined.
SCANA and Westvaco each own a 50 percent 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. The
facility began operations in March 1999. Financing for the facility of
approximately $139.8 million was provided to Cogen by banks. On September 10,
1998 the contractor in charge of construction filed suit in South Carolina
Circuit Court seeking approximately $52 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 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.
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 SCE&G and Fuel
Company and 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 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.
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, overlapping service areas. 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 Adjustments/ Consolidated
1999 Operations Distribution Other Eliminations Total
- --------------------------- ----------------------------------------------------
External Customer Revenue $1,226 $239 $ 2 $ - $1,467
Intersegment Revenue 203 2 - (205) -
Operating Income (Loss) 275 17 (4) (5) 283
Interest Expense 5 n/a 4 93 102
Depreciation & Amortization 141 13 - - 154
Segment Assets 4,452 399 222 (669) 4,404
Expenditures for Assets 198 19 13 - 230
Deferred Tax Assets 2 n/a - 14 16
- --------------------------- ----------------------------------------------------
- --------------------------------------- ------------- ----------- --------------
Electric Gas All Adjustments/ Consolidated
1998 Operations Distribution Other Eliminations Total
- --------------------------------------- ------------- ------ ----------------- -
External Customer Revenue $1,220 $230 $ 1 $ - $1,451
Intersegment Revenue 201 3 - (204) -
Operating Income (Loss) 307 21 (5) (11) 312
Interest Expense 4 n/a 4 86 94
Depreciation & Amortization 120 11 - - 131
Assets 4,305 381 209 (649) 4,246
Expenditures for Assets 179 19 39 8 245
Deferred Tax Assets 1 n/a - 20 21
- --------------------------------------- ------------- ------ ----------------- -
- ---------------------------------------- ------------- ----------- ------------
Electric Gas All Adjustments/ Consolidated
1997 Operations Distribution Other Eliminations Total
- ---------------------------------------- ------------- ----------- -------------
External Customer Revenue $1,103 $234 $ 1 $ - $1,338
Intersegment Revenue 24 1 - (25) -
Operating Income (Loss) 269 22 (4) (5) 282
Interest Expense n/a 1 89 95 5
Depreciation & Amortization 129 11 - - 140
Assets 4,240 364 227 (777) 4,054
Expenditures for Assets 186 15 32 (1) 232
Deferred Tax Assets n/a - 20 21 1
- ---------------------------------------- ------------- ----------- -------------
Revenues 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 1999, 1998 or 1997.
Significant non-cash activities included the Charleston electric franchise
agreement and the Charleston environmental agreement related to a MGP site.
Management uses operating income to measure segment profitability for
regulated operations. Accordingly, the Company does not allocate interest
charges or income tax expense/(benefit) to its segments. Similarly, management
evaluates utility plant for its segments. Therefore, the Company does not
allocate 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.
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. Segment assets include utility plant only
(excluding accumulated depreciation) for all segments. As a result, adjustments
to assets include accumulated depreciation, offset in part by common and
non-utility plant and non-fixed assets for the segments.
Adjustments to Interest Charges and Deferred Tax Assets include
primarily the unallocated amounts from the Company. Interest Charges is also
adjusted to eliminate inter-segment charges. Deferred Tax Assets are also
adjusted to remove the non-current portion of those assets.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1999
- -------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------------------------------------
(Millions of Dollars, except per share amounts)
Total operating revenues $353 $338 $431 $345 $1,467
Operating income 72 60 101 50 283
Net income 48 37 77 27 189
- --------------------------------------------- --------- --------- -----------
1998
- -------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- ------------------------------------------------------------- ------------ ----
(Millions of Dollars, except per share amounts)
Total operating revenues $358 $343 $431 $319 $1,451
Operating income 83 67 112 50 312
Net income 60 44 88 35 227
- ---------------------------------------------------------------------- --------
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 20 herein. The other
information required by Item 10 is incorporated herein by reference, pursuant to
General Instruction G(3) to Form 10-K, to the captions Election of Directors
Items 1, 2 and 3, Continuing Directors, and Other Information - Section 16(a)
Beneficial Ownership Reporting Compliance in SCANA's definitive proxy statement
for the 2000 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 22, 1999 (except as
otherwise indicated) to hold office until the next annual meeting of SCE&G's
stockholders on April 27, 2000.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 56 For more than five years, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Amick Processing, Inc.
and Amick Broilers, Inc., Batesburg, SC
(vertically integrated broiler operations).
Director, SCANA Corporation, Columbia, SC.;
Public Service Company of North Carolina,
Inc., (PSNC), Gastonia, NC; Blue Cross and
Blue Shield of South Carolina, Columbia,
SC.
James A. Bennett 39 Since February 2000, Economic Development
(1997) Director, First Citizens Bank, Columbia, SC.
From December 1998 to February 2000, Senior Vice
President and Director of Professional Banking,
First Citizens Bank.
From December 1994 to December 1998, Senior
Vice President and Director of Community
Banking, First Citizens Bank.
Director, SCANA Corporation; PSNC, Gastonia,
NC.
William B. Bookhart, Jr. 58 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
Name and Year First
Became Director Age Principal Occupation; Directorships
William C. Burkhardt* 62 For more than five years, President and Chief
(2000) Executive Officer of Austin Quality Foods,
Inc., Cary, NC.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; Capital Bank, Raleigh,
NC.
Hugh M. Chapman 67 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.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; West Point-Stevens,
West Point, GA; PrintPack, Inc., Atlanta,
GA; The Williams Companies, Inc., Tulsa,
OK.
Elaine T. Freeman 64 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg, SC.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; National Bank of South
Carolina, Columbia, SC.
Lawrence M. Gressette, Jr. 68 Since February 28, 1997, Chairman Emeritus
(1987) of SCANA Corporation, Columbia, SC.
For more than five years prior to February
28, 1997, Chairman of the Board and Chief
Executive Officer of SCANA
Corporation.
For more than five years prior to December
13, 1995, President of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
D. Maybank Hagood 38 For more than five years, President and Chief
(1999) Executive Officer of William M. Bird and
Company, Inc., Charleston, SC (wholesale
distributor of floor covering materials).
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
W. Hayne Hipp 60 For more than five years, Chairman, President
(1983) and Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance and
broadcasting holding company).
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; The Liberty
Corporation, Greenville, SC; Wachovia
Corporation, Winston-Salem, NC.
Name and Year First
Became Director Age Principal Occupation; Directorships
Lynne M. Miller 48 Since February 1998, Chief Executive Officer
(1997) of Environmental Strategies Corporation,
Reston, VA (environmental consulting and
engineering).
For more than five years prior to February 1998,
President of Environmental Strategies
Corporation.
Director, SCANA Corporation, Columbia, SC; PSNC,
Gastonia, NC; Adams National Bank, Washington,
DC.
John B. Rhodes 69 For more than five years, Chairman and Chief
(1967) Executive Officer, Rhodes Oil Company, Inc.,
Walterboro, SC (distributor of petroleum
products).
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
Maceo K. Sloan 50 For more than five years, Chairman, President
(1997) and Chief Executive Officer of Sloan Financial
Group, Inc. (holding company) and Chairman and
Chief Executive Officer of NCM Capital
Management Group, Inc. (investment company),
Durham, NC.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; MRF Bankcorp, Inc.,
and its subsidiary Farmers and Mechanics
Bank, Durham, NC; Virtual Technology
Corporation, Minneapolis, MN.
Harold C. Stowe 53 Since March 1997, President and Chief Executive
(1999) Officer of Canal Industries, Inc., Conway, SC
(forest products industry).
From 1996 to March 1997, Co-President of
Canal Industries, Inc.
From 1991 to 1996, Executive Vice President
of CSI Group, Inc., a division of Canal
Industries, Inc.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; Canal Industries,
Inc., Conway, SC; Ruddick Corporation,
Charlotte, NC.
Name and Year First
Became Director Age Principal Occupation; Directorships
William B. Timmerman 53 Since March 1, 1997, Chairman and Chief
(1991) Executive Officer of SCANA Corporation,
Columbia, SC.
Since December 13, 1995, President of SCANA
Corporation.
From August 21, 1996 to March 1, 1997, Chief
Operating Officer of SCANA Corporation.
From May 1, 1994 to December 13, 1995,
Executive Vice President of SCANA
Corporation.
From at least March 1, 1995 to February 20,
1996, Chief Financial Officer and
Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; Powertel, Inc., West
Point, GA; ITC^DeltaCom, Inc. West Point,
GA; The Liberty Corporation, Greenville,
SC.
G. Smedes York* 59 For more than five years, President and
(2000) treaser of York Properties, Inc., Raleigh,
NC.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
Charles E. Zeigler, Jr.* 53 Since February 2000, President and Chief
(2000) Operating Officer of PSNC, Gastonia, NC.
From February 1993 to February 2000,
Chairman, President and Chief Executive
Officer of PSNC.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
* Became a director of SCE&G on March 15, 2000.
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 53 Chairman of the Board and
Chief Executive Officer 1997-present
President, SCANA 1995-present
Chief Operating Officer,
SCANA 1996-1997
President, SCI,
an affiliate 1996-1997
Executive Vice President, SCANA *-1995
Chief Financial Officer and
Controller, SCANA *-1996
J. L. Skolds 49 President and Chief
Operating Officer 1996-present
Senior Vice President -
Generation *-1996
Senior Vice President -
Nuclear Operations *-1995
K. B. Marsh 44 Senior Vice President - Finance,
Chief Financial Officer and
Controller, SCANA 1998-present
Vice President 1996-present
Vice President - Finance,
Chief Financial Officer
and Controller, SCANA 1996-1998
Vice President - Finance,
Treasurer and Secretary,
SCANA *-1996
H. T. Arthur 54 Senior Vice President and
General Counsel 1998-present
Vice President and General
Counsel 1996-1998
*Indicates position held at least since March 1, 1995
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 1999 all Section
16(a) filing requirements applicable to its executive officers, directors and
greater than 10 percent 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 2000 annual meeting
of shareholders.
SCE&G: The information called for by Item 11, Executive Compensation, is as
follows:
SUMMARY COMPENSATION TABLE
Name and Principal Year Annual Compensation Long-Term
Position Compensation(2)(3)
Other Payouts (4)
(1) Annual LTIP All Other
Salary Bonus Compensation Payouts Compensation
($) ($) ($) ($) ($)
W. B. Timmerman
Chairman, President 1999 490,313 312,900 17,212 298,813 29,419
and Chief Executive 1998 455,909 303,780 17,514 - 27,138
Officer - SCANA 1997 400,634 318,815 12,220 88,338 24,038
J. L. Skolds 1999 330,665 168,288 16,232 150,618 19,840
President and Chief 1998 305,123 163,399 14,099 - 18,201
Operating Officer - SCE&G 1997 277,132 161,677 5,777 70,283 16,628
K. B. Marsh 1999 241,354 128,058 10,337 81,555 14,481
Senior Vice President- 1998 219,860 99,372 8,654 - 13,122
Finance, Chief Financial 1997 199,845 104,276 2,945 44,491 11,991
Officer and Controller -
SCANA
H. T. Arthur 1999 219,806 93,825 15,939 65,843 13,188
Senior Vice President 1998 203,162 99,372 9,534 - 12,190
and General Counsel 1997 178,173 84,438 5,158 23,858 10,690
G. J. Bullwinkel 1999 239,973 93,825 14,172 81,555 14,398
Senior Vice President 1998 229,152 99,372 11,726 - 11,726
- Governmental Affairs, 1997 219,273 92,796 7,776 70,283 7,776
Economic Development and
Customer Relations
- -----------------
(1) Payments under the Annual Incentive Plan.
(2) For 1999, 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 $9,000, $7,435 and $777 for Mr.
Timmerman; $9,000, $6,878 and $354 for Mr. Skolds; $9,000, $1,183 and
$154 for Mr.Marsh; $9,000, $6,830, and $109 for Mr. Arthur and $9,000,
$4,993 and $179 for Mr. Bullwinkel.
(3) Payments under the Performance Share Plan.
(4) All other compensation for all named executive officers consists solely of
contributions to defined contribution plans.
The following table lists the target awards made in 1999 (for potential
payment in 2002) 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
Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation Threshold Target Maximum
Name Rights(#) or Payout (#) (#) (#)
W. B. Timmerman 9,700 1999-2001 3,880 9,700 14,550
J. L. Skolds 4,890 1999-2001 1,956 4,890 7,335
K. B. Marsh 3,780 1999-2001 1,512 3,780 5,670
H. T. Arthur 2,640 1999-2001 1,056 2,640 3,960
G. J. Bullwinkel 2,640 1999-2001 1,056 2,640 3,960
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 eligible employees, SCANA
has Supplemental Executive Retirement Plans ("SERPs") for certain eligible
employees, including officers. A SERP is an unfunded plan, that provides for
benefit payments in addition to those payable under a qualified retirement plan.
It maintains uniform application of the Retirement Plan benefit formula and
would provide, among other benefits, payment of Retirement Plan formula pension
benefits, if any, which exceed those payable under the Internal Revenue Code
("IRC") maximum benefit limitations.
The following table illustrates the estimated maximum annual benefits
payable upon retirement at normal retirement date under SCANA's Retirement Plan
and the SERPs.
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
--------------------------------------------------------------
$150,000 $ 41,578 $ 55,437 $ 69,296 $ 83,156 $ 85,765
200,000 56,578 75,437 94,296 113,156 117,015
250,000 71,578 95,437 119,296 143,156 148,265
300,000 86,578 115,437 144,296 173,156 179,515
350,000 101,578 135,437 169,296 203,156 210,765
400,000 116,578 155,437 194,296 233,156 242,015
450,000 131,578 175,437 219,296 263,156 273,265
500,000 146,578 195,437 244,296 293,156 304,515
550,000 161,578 215,437 269,296 323,156 335,765
600,000 176,578 235,437 294,296 353,156 367,015
650,000 191,578 255,437 319,296 383,156 398,265
700,000 206,578 275,437 344,296 413,156 429,515
750,000 221,578 295,437 369,296 443,156 460,765
800,000 236,578 315,437 394,296 473,156 492,015
850,000 251,578 335,437 419,296 503,156 523,265
900,000 266,578 355,437 444,296 533,156 554,515
950,000 281,578 375,437 469,296 563,156 585,765
1,000,000 296,578 395,437 494,296 593,156 617,015
For all the executive officers included in the Summary Compensation
Table, the 1999 compensation shown in the column labeled "Salary" of the Summary
Compensation Table is covered by the Retirement Plan or SERP. As of December 31,
1999, Messrs. Timmerman, Skolds, Arthur, Bullwinkel and Marsh had credited
service under the Retirement Plan (or its equivalent under the SERP) of 21, 13,
17, 28 and 15 years, respectively. Benefits are computed based on a
straight-life annuity with an unreduced 60 percent surviving spouse benefit. The
amounts in the above table assume continuation of the primary Social Security
benefits in effect at January 1, 2000 and are not subject to any deduction for
Social Security or other offset amounts.
SCANA has a Key Employee Retention Plan (the "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
in some cases, completion of 35 years of service with the Company) equal to 25
percent 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 percent 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 percent 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 percent per year), to the executive
officers named in the Summary Compensation Table are as follows: Mr.
Timmerman-$185,129; Mr. Skolds-$147,276; Mr. Arthur-$80,102, Mr.
Bullwinkel-$97,715 and Mr. Marsh-$131,754 .
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 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 Severance 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
Plan 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 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, as applicable.
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
percent of the targeted awards for all performance periods which are not
yet completed 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 1999 fiscal year, decisions on various elements of executive
compensation were made by the Management Development and Corporate Performance
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
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. 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, 1999, 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) is related.
Mr. Amick is President and a 20 percent 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 1999,
SCANA participated in a shared sponsorship agreement with Powertel Inc., a
wireless personal communications services (PCS) provider, to sponsor the Team
Amick Racing Car. SCANA's portion of the sponsorship during 1999 was $841,797,
pursuant to which SCANA received promotional considerations associated with
NASCAR racing. Powertel's sponsorship was approximately $600,000. As of January
31, 2000, SCANA Communications Holdings, Inc., a subsidiary of SCANA, owned a
32.41 percent interest in Powertel.. SCANA is not continuing as a primary
sponsor but has sponsorship rights for advertising up to an amount of $250,000
with Team Amick Motor Sports LLC in 2000. SCANA has been informed that Powertel
will continue its primary sponsorship for 2000.
Directors Compensation
Board Fees
Officers of SCANA who are also directors do not receive additional
compensation for their service as directors. Since April 1999, compensation for
non-employee directors has included the following:
o an annual retainer of $19,400 (41 percent 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 director, the amount that would have resulted
from investing the deferred amounts in an interest bearing savings account.
Since January 1, 1999, the interest rate has been set at the announced
prime rate as published in the Money Rates Section of The Wall Street Journal.
Mr. Rhodes and Mr. Bennett were the only directors participating in the plan
during 1999. Mr. Rhodes became a participant in July 1987, and Mr. Bennett in
December 1997. During 1999, interest credited to Mr. Rhodes' deferral account
was $34,953 and interest credited to Mr. Bennett's deferral account was $827.
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
caption Share Ownership of Directors, Nominees and Executive Officers and Five
Percent Owner of SCANA Common Stock in SCANA's definitive proxy statement for
the 2000 annual meeting of shareholders.
SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The
following table list shares of SCANA common stock beneficially owned on March
10, 2000 by each director, each nominee and each executive officer named in the
Summary Compensation table on page 109.
SECURITY OWNERSHIP OF MANAGEMENT
Amount and Nature Amount and Nature
of Beneficial Ownership of of Beneficial Ownership of
SCANA Common Stock *(1) (2) SCANA Common Stock *(1) (2)(3)
Name Name
- ----- ----- ---
B. L. Amick 10,785 W. H. Hipp 4,084
H. T. Arthur 11,860 K. B. Marsh 13,613
J. A. Bennett 1,556 L. M. Miller 1,834
W. B. Bookhart, Jr. 20,424 J. B. Rhodes 11,560
G. J. Bullwinkel 26,495 J. L. Skolds 13,365
W. C. Burkhardt 3,066 M. S. Sloan 2,826
H. M. Chapman 6,844 H. C. Stowe 3,284
E. T. Freeman 5,236 W. B. Timmerman 50,844
L. M. Gressette, Jr. 62,490 G. S. York 8,561
D. M. Hagood 347 C. E. Zeigler, Jr. 26,025
*Each of the directors, nominees and named executive officers owns less than 1%
of the shares outstanding.
All directors and executive officers as a group (19 persons) TOTAL 258,604.TOTAL
PERCENT OF CLASS, outstanding and entitled to vote at the Annual Meeting of
Shareholders 0.2%.---------- 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-5,567; Mr.
Gressette-1,060; and by all directors, nominees and executive officers 7,107 in
total. (2) Includes shares purchased through February 29, 2000, by the Trustee
under SCANA's Stock Purchase Savings Plan. (3) Includes shares that may be
issued within 60 days under the Performance Share Plan on account of the
1997-1997 performance period.
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 captions Compensation
Committee Interlocks and Insider Participation and Other Related Transactions in
SCANA's definitive proxy statement for the 2000 annual meeting of stockholders.
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
SCANA's definitive proxy statement for the 2000 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 under the heading 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.
The Financial Statement Schedules filed as part of this
report for SCANA and SCE&G are listed beginning on page 117.
(2) Exhibits
Exhibits required to be filed with this Annual Report on
Form 10-K are listed in the Exhibit Index following the
signature page. Certain of such exhibits which have
heretofore been filed with the 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 SCANA'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), instruments defining
the rights of holders of long-term debt of less than 10
percent of the total consolidated assets of SCANA and its
subsidiaries, have been omitted and SCANA agrees to furnish
a copy of such instruments to the Commission upon request.
(b) Reports on Form 8-K during the fourth quarter of 1999
None
SCANA:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
1998, 1998 and 1997.
For December 31, 1999 Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts From Reserves Balance
- ---------------------------------------------------------------------------------------------- ----------------
Reserves deducted from related assets
on the balance sheet:
Uncollectible accounts 1,965,732 5,636,123 - 299,582 7,302,273
Reserves other than those deducted
from assets on the balance sheet:
Reserve for investment impairment 10,292,611 - - 6,158,843 4,133,768
Reserve for injuries and damages 4,287,986 1,352,448 - 418,890 5,221,544
Provision for pension and benefit
Staff Reduction Plan 6,256,249 231,116 - - 6,487,365
Provision for environmental
remediation and settlement 3,619,572 - - 395,751 3,223,821
For December 31, 1998 Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts from Reserves Balance
- --------------------------------------- ---------------- ---------------- ------------------ ---------------- -------------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts 1,807,047 184,257 - 25,572 1,965,732
Reserves other than those deducted from assets on the balance sheet:
Reserve for investment impairment 11,150,060 - - 857,449 10,292,611
Reserve for injuries and damages 4,187,594 461,462 - 361,070
4,287,986
Provision for pension and benefit
Staff Reduction Plan 4,486,895 6,256,249 - 4,486,895
6,256,249
Provision for environmental
remediation and settlement 4,006,562 - - 386,990
3,619,572
For December 31, 1997 Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts from Reserves Balance
- --------------------------------------- ---------------- ---------------- ------------------ ---------------- -------------------
Reserves deducted from related assets on the balance sheet:
Uncollected accounts 2,513,126 424 - 706,503 1,807,047
Reserves other than those deducted from assets on the balance sheet:
Reserve for investment impairment 5,426,426 5,723,634 - - 11,150,060
Reserve for injuries and damages 5,135,643 1,158,902 - 2,106,951 4,187,594
Provision for pension and benefit
Staff Reduction Plan 3,383,261 1,103,634 - -
4,486,895
Provision for environmental
remediation and settlement 3,187,393 819,169 - -
4,006,562
SCE&G:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
1999, 1998 and 1997.
For December 31, 1999 Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts from Reserves Balance
- --------------------------------------- ---------------- ---------------- ---------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts 611,001 80,000 - 154,001 537,000
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages 4,176,794 104,000 - 307,978 3,972,816
Provision for pension and benefit
Staff Reduction Plan - - - - -
Provision for environmental
remediation and settlement 3,619,572 - - 395,751 3,223,821
For December 31, 1998 Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts from Reserves Balance
- --------------------------------------- ---------------- ---------------- ---------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts 611,001 - - - 611,001
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages 4,039,148 460,462 - 322,816 4,176,794
Provision for pension and benefit
Staff Reduction Plan 4,486,895 - - 4,486,895 -
Provision for environmental
remediation and settlement 4,006,562 - - 386,990 3,619,572
For December 31, 1997 Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts from Reserves Balance
- --------------------------------------- ---------------- ---------------- ---------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts 873,001 - - 262,000 611,001
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages 5,135,643 1,010,456 - 2,106,951 4,039,148
Provision for pension and benefit
Staff Reduction Plan 3,383,261 1,103,634 - - 4,486,895
Provision for environmental
remediation and settlement 3,187,393 819,169 - - 4,006,562
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
W. B. Timmerman, Chairman of the Board,
President, Chief Executive Officer and Director
By: s/K. B. Marsh
(K. B. Marsh, Attorney-in-fact)
DATE: March 24, 2000
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, President,
Chief Executive Officer and Director
(Principal Executive Officer)
By: s/K. B. Marsh
K. B. Marsh, Senior Vice President - Finance,
Chief Financial Officer and Controller
(Principal Financial and Accounting Officer)
DATE: March 24, 2000
Directors:
B. L. Amick W. H. Hipp
J. A. Bennett L. M. Miller
W. B. Bookhart, Jr. J. B. Rhodes
W. C. Burkhardt M. K. Sloan
H. M. Chapman H. C. Stowe
E. T. Freeman G. S. York
L. M. Gressette, Jr. C. E. Zeigler, Jr.
D. M. Hagood
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
By: s/K. B. Marsh
(K. B. Marsh, Attorney-in-Fact)
Date: March 24, 2000
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)
By: s/K. B. Marsh
K. B. Marsh, Senior Vice President - Finance and
Chief Financial Officer
(Principal Financial Officer)
Date: March 24, 2000
By: s/J. E. Addison
J. E. Addison, Vice President and Controller
(Principal Accounting Officer)
Date: March 24, 2000
Directors:
B. L. Amick W. H. Hipp
J. A. Bennett L. M. Miller
W. B. Bookhart, Jr. J. B. Rhodes
W. C. Burkhardt M. K. Sloan
H. M. Chapman H. C. Stowe
E. T. Freeman G. S. York
L. M. Gressette, Jr. C. E. Zeigler, Jr.
D. M. Hagood
EXHIBIT INDEX
Applicable to
Exhibit Form 10-K of
No. SCANA SCE&G Description
2.01 X Agreement and Plan of Merger, dated as of February
16, 1999 as amended and restated as of May 10, 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 2.1 to
SCANA Form S-4 on May 11, 1999 and incorporated by
reference herein)
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 and incorporated
by reference herein)
3.02 X Restated Articles of Incorporation of SCE&G, as
adopted on December 15, 1993 (Filed as Exhibit 3.01
to Registration Statement No. 333-86387 and
incorporated by reference herein)
3.03 X Articles of Amendment of SCANA, dated April 27, 1995
(Filed as Exhibit 4-B to Registration Statement No.
33-62421 and incorporated by reference herein)
3.04 X Articles of Amendment of SCE&G, dated June 7, 1994
and filed June 9, 1994 (Filed as Exhibit 3.02 to
Registration Statement No. 333-86387 and incorporated
by reference herein)
3.05 X Articles of Amendment of SCE&G, dated November 9,
1994 (Filed as Exhibit 3.03 to Registration Statement
No. 333-86387 and incorporated by reference herein)
3.06 X Articles of Amendment of SCE&G, dated December 9,
1994 (Filed as Exhibit 3.04 to Registration Statement
No. 333-86387 and incorporated by reference herein)
3.07 X Articles of Correction of SCE&G, dated January 17,
1995 (Filed as Exhibit 3.05 to Registration Statement
No. 333-86387 and incorporated by reference herein)
3.08 X Articles of Amendment of SCE&G, dated January 13,
1995 and filed January 17, 1995 (Filed as Exhibit
3.06 to Registration Statement No. 333-86387 and
incorporated by reference herein)
3.09 X Articles of Amendment of SCE&G, dated March 30, 1995
(Filed as Exhibit 3.07 to Registration Statement No.
333-86387 and incorporated by reference herein)
3.10 X Articles of Correction of SCE&G - Amendment to
Statement filed March 30, 1995, dated December 13,
1995 (Filed as Exhibit 3.08 to Registration Statement
No. 333-86387 and incorporated by reference herein)
3.11 X Articles of Amendment of SCE&G, dated December 13,
1995 (Filed as Exhibit 3.09 to Registration Statement
No. 333-86387 and incorporated by reference herein)
3.12 X Articles of Amendment of SCE&G, dated February 18,
1997 (Filed as Exhibit 3-L to Registration Statement
No. 333-24919 and incorporated by reference herein)
Applicable to
Exhibit Form 10-K of
No. SCANA SCE&G Description
3.13 X Articles of Amendment of SCE&G, dated February 21,
1997 (Filed as Exhibit 3.11 to Registration Statement
No. 333-86387 and incorporated by reference herein)
3.14 X Articles of Amendment of SCE&G, dated April 22, 1997
(Filed as Exhibit 3.12 to Registration Statement No.
333-86387 and incorporated by reference herein)
3.15 X Articles of Amendment of SCE&G, dated April 9, 1998
(Filed as Exhibit 3.13 to Registration Statement No.
333-86387 and incorporated by reference herein)
3.16 X Articles of Amendment of SCE&G, dated May 19, 1999
(Filed herewith on page 130)
3.17 X Articles of Amendment of SCE&G, dated August 13, 1999
(Filed herewith on page 132)
3.18 X Articles of Amendment of SCE&G, dated March 1, 2000
(Filed herewith on page 134)
3.19 X By-Laws of SCANA as revised and amended on February
22, 2000. (Filed herewith on page 136)
3.20 X By-Laws of SCE&G as amended and adopted on February
22, 2000. (Filed herewith on page 156)
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 and incorporated by reference
herein)
4.02 X Indenture dated as of November 1, 1989 between SCANA
Corporation and The Bank of New York, as Trustee
(Filed as Exhibit 4-A to Registration No. 33-32107 and
incorporated by reference herein)
4.03 X X Indenture dated as of January 1, 1945, between the
South Carolina Power Company and 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 and
incorporated by reference herein)
4.04 X X Fourth Supplemental Indenture dated as of April 1,
1950, to Indenture referred to in Exhibit 4.03,
pursuant to which SCE&G assumed said Indenture
(Exhibit 2-C to Registration Statement No. 2-26459 and
incorporated by reference herein)
Applicable to
Exhibit Form 10-K of
No. SCANA SCE&G Description
4.05 X X Fifth through Fifty-third Supplemental Indenture referred to in
Exhibit 4.03 dated as of the dates indicated below and filed as
exhibits to the Registration Statements whose file numbers are set
forth below and are incorporated by reference herein
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
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
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
May 1, 1999 Exhibit 4.04 to Registration No. 333-86387
Applicable to
Exhibit Form 10-K of
No. SCANA SCE&G Description
4.06 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-F to Registration
Statement No. 33-49421 and incorporated by reference herein)
4.07 X X First Supplemental Indenture to Indenture referred
to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-49421 and incorporated by
reference herein)
4.08 X X Second Supplemental Indenture to Indenture referred to in
Exhibit 4.06 dated as of June 15, 1993
(Filed as Exhibit 4-G to Registration Statement No. 33-57955 and
incorporated by reference herein)
4.09 X X Trust Agreement for
SCE&G Trust I (Filed as Exhibit 4-G to SCE&G Form 10-K for the
year ended December 31, 1997 and incorporated by reference
herein)
4.10 X X Certificate of Trust of SCE&G Trust I (Filed as
Exhibit 4-H to SCE&G Form 10-K for the year ended December 31,
1997 and incorporated by reference herein)
4.11 X X Junior
Subordinated Indenture for SCE&G Trust I (Filed as Exhibit 4-I to
SCE&G Form 10-K for the year ended December 31, 1997 and
incorporated by reference herein)
4.12 X X Guarantee
Agreement for SCE&G Trust I (Filed as Exhibit 4-J to SCE&G Form
10-K for the year ended December 31, 1997 and incorporated by
reference herein)
4.13 X X Amended and Restated Trust Agreement
for SCE&G Trust I (Filed as Exhibit 4-K to SCE&G Form 10-K for
the year ended December 31, 1997 and incorporated by reference
herein) 9.01 Voting Trust Agreement (Not Applicable)
10.01 X SCANA Voluntary Deferral Plan as amended through October 21, 1997
(Filed as Exhibit 10.01(a) to Registration Statement No.
333-86803 and incorporated by reference herein)
10.02 X SCANA Supplemental Executive Retirement Plan as amended and
restated effective as of October 21, 1997 (Filed as Exhibit
10.01(b) to Registration Statement No. 333-86803 and
incorporated by reference herein)
10.03 X SCANA Supplementary Voluntary Deferral
Plan as amended and restated through October 21, 1997 (Filed as
Exhibit 10-B to SCANA Form 10-K for the year ended December 31,
1997 and incorporated by reference herein)
10.04 X SCANA Key Executive Severance Benefits Plan as amended and
restated effective as of October 21, 1997 (Filed as Exhibit
10.01(c) to Registration Statement No. 333-86803 and
incorporated by reference herein)
10.05 X SCANA Supplementary Key Executive Severance Benefits Plan
effective as of December 17, 1997 (Filed
as Exhibit 10.01(d) to Registration Statement No. 333-86803 and
incorporated by reference herein)
Applicable to
Exhibit Form 10-K of
No. SCANA SCE&G Description
10.06 X SCANA Performance Share Plan as amended and restated
effective December 1, 1999 (Filed herewith on page 177)
10.07 X 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
and incorporated by reference herein)
10.08 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 and
incorporated by reference herein)
10.09 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 and incorporated by reference herein)
10.10 X SCANA Corporation Nonemployee Director Stock Plan
effective January 1, 1997 (Filed as Exhibit 4.3 to
Registration Statement No. 333-18973 and incorporated by
reference herein)
11.01 Statement Re Computation of Per Share Earnings
(Not Applicable)
12.01 X X Statements Re Computation of Ratios
13.01 Annual Report to Security Holders, Form 10-Q or Quarterly
Report to Security Holders (Not Applicable)
16.01 Letter Re Change in Certifying Accountant (Not Applicable)
18.01 Letter Re Change in Accounting Principles (Not Applicable)
21.01 Subsidiaries of the Registrant (Not Applicable)
22.01 Published Report Regarding Matters Submitted to Vote of
Security Holders (Not Applicable)
23.01 X Consents of Experts and Counsel
Independent Auditors' Consent
23.02 X Consents of Experts and Counsel
Independent Auditors' Consent
24.01 Power of Attorney (Not Applicable)
27.01 X Financial Data Schedule
27.02 X Financial Data Schedule
99.01 Additional Exhibits (Not Applicable)